ARC Resources Ltd. Announces the 8th Consecutive Year Of ~200% Reserves Replacement, 2015 Finding and Development Costs for 2P Reserves of $6.97 and a Significant Increase in Montney Resource Estimates in 2015

CALGARY, Feb. 10, 2016 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") is pleased to report its 2015 year-end reserves and resources information.

"ARC's team once again demonstrated the strength of its asset base and technical expertise, replacing 190 per cent of produced reserves through the drill bit at low finding and development costs of $6.97 per boe for proved plus probable reserves. These results showcase ARC's exceptional Montney assets, which were the main driver of both reserves replacement and positive technical revisions. An updated Independent Resources Evaluation for our northeast British Columbia and Pouce Coupe assets realized a significant increase in the identified resource base on ARC's lands in the area. With exceptional capital and operating efficiencies and strong well performance, ARC's world-class Montney assets provide ARC with tremendous long-term development opportunities – which our team will pursue in our tradition of prudent capital management and paced development," stated Myron Stadnyk, President and CEO.


HIGHLIGHTS

  • Replaced 190 per cent of 2015 total production, adding 78.7 MMboe of proved plus probable ("2P") reserves through development capital activities. Over the last eight years, ARC has delivered an average of 200 per cent produced reserves replacement through the drill bit.
  • Positive technical revisions of 36 MMboe (2P) were realized, predominantly in Tower, Sunrise and Dawson, reflecting the strong well performance of ARC's Montney assets. These more than offset the removal of 15 MMboe due to the decrease in commodity prices since year-end 2014.
  • Proved developed producing ("PDP") reserves increased from 210 MMboe to 222 MMboe. The increase in PDP reserves was driven by northeast British Columbia ("NE BC") Montney properties, which increased to 115 MMboe at year-end 2015 from 84 MMboe at year-end 2014.
  • Replaced 175 per cent of 2015 natural gas production, adding 0.3 Tcf of 2P natural gas reserves. Replaced approximately 210 per cent of 2015 oil and natural gas liquids ("NGLs") production, adding 31 MMbbl of 2P oil and NGLs reserves. Material reserves growth was realized in the NE BC Montney region, particularly in Tower, Sunrise and Dawson.
  • Finding and Development ("F&D") costs of $6.97 per boe for 2P reserves and $8.20 per boe for proved reserves, excluding Future Development Capital ("FDC") and F&D costs of $8.31 per boe for proved producing reserves. Significant NE BC Montney reserve additions combined with capital reductions contributed to the 39 per cent reduction in 2P F&D costs relative to 2014.
  • Significant FDC reduction from $3.6 billion at year-end 2014 to $2.7 billion at year-end 2015. This was mainly attributed to a decrease in drilling, completions and facility capital costs, as well as the removal of capital associated with various dispositions.
  • ARC updated an Independent Resources Evaluation ("Resources Evaluation" or "Independent Resources Evaluation") for its lands in the NE BC Montney region, including lands at Pouce Coupe in Alberta. The updated evaluation realized a significant increase in the identified resource base on ARC's NE BC Montney lands. The shale gas Total Petroleum Initially in Place ("TPIIP") increased 33 per cent from 67.4 Tcf in 2014 to 90 Tcf in 2015 and tight oil TPIIP increased 315 per cent from 2.3 billion barrels of oil in 2014 to 9.7 billion barrels in 2015 (1).

(1)

Year-end 2015 complies with current Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") guidelines. Resources Evaluation volumes provided are the "Best Estimate" case. Year-end 2015 and 2014 TPIIP estimates utilize a one per cent porosity cut-off for shale gas based upon "Best Estimate" case. Estimates for both 2015 and 2014 were determined using a three per cent porosity cut-off for tight oil based upon "Best Estimate" case.

2015 INDEPENDENT RESERVES EVALUATION

GLJ Petroleum Consultants ("GLJ") conducted an Independent Reserves Evaluation effective December 31, 2015, which was prepared in accordance with definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The reserves evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2016 as outlined in Table 1 below.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without the inclusion of any royalty interest) unless otherwise noted. All reserves information has been prepared in accordance with NI 51-101. In addition to the detailed information disclosed in this news release, more detailed information will be included in ARC's Annual Information Form ("AIF") for the year ended December 31, 2015, which will be filed on SEDAR at www.sedar.com on or before March 30, 2016.

Based on this Independent Reserves Evaluation, ARC's reserves profile as at December 31, 2015 is summarized below:

  • Two per cent increase in 2015 2P reserves to 687 MMboe compared to 673 MMboe of 2P reserves at year-end 2014. 2P reserves are comprised of 2.9 Tcf of natural gas and 200 MMbbl of oil and NGLs at year-end 2015.
  • 78.7 MMboe of 2P reserve additions from exploration and development activities (including revisions), before net dispositions of 23 MMboe and 2015 production of 42 MMboe. Technical revisions of 36 MMboe more than offset the removal of 15 MMboe due to the decrease in commodity prices since year-end 2014.
  • 190 per cent replacement of 2P reserves based on 78.7 MMboe of 2P reserve additions and 2015 production of 42 MMboe.
  • Total proved reserves account for 57 per cent of 2P reserves.
  • PDP reserves represent 56 per cent of total proved reserves and 32 per cent of 2P reserves.
  • Oil and NGLs comprise 29 per cent of 2P reserves and natural gas comprises 71 per cent of 2P reserves, using the commonly accepted boe conversion ratio of six Mcf to one barrel.
  • The downward change in FDC, which exceeded the 2015 capital spent, resulted in negative one-year 2P F&D costs, including FDC, of ($2.82) per boe for 2015, and $8.11 per boe for the three-year average. Proved F&D costs, including FDC, were $0.19 per boe for 2015 and $11.61 per boe for the three-year average. Given the large reduction in FDC, one-year F&D costs, including FDC, are not meaningful.
  • Strong reserve life index ("RLI") of 15.9 years, up from 15.0 years at year-end 2014. The increase in RLI is attributed to reserves growth in 2015 as well as modest expected production growth in 2016 as a result of reduced capital expenditures. For details on ARC's 2016 production guidance, see the February 10, 2016 news release entitled, "ARC Resources Ltd. Announces Strong Fourth Quarter, Record Annual Production and a Siginificant Increase in Montney Resource Estimate in 2015".
  • Recycle ratio of 2.4 times and 2.5 times for the current year and the three-year average, respectively, for 2P reserves based on current and three-year average F&D costs, excluding FDC, based on current and three-year average operating netbacks of $16.69 per boe and $25.91 per boe, respectively.
  • Abandonment and reclamation costs of $527 million (undiscounted) have been included in the 2P reserves, which account for the abandonment and reclamation of all wells to which reserves have been attributed.

Table 1










GLJ Price Forecast


WTI Crude Oil


Edmonton Light Oil


AECO Natural Gas


Foreign Exchange

at January 1


(US$/bbl)


(Cdn$/bbl)


(Cdn$/MMbtu)


(US$/Cdn$)



2016

2015


2016

2015


2016

2015


2016

2015

2016


44.00

75.00


55.86

80.00


2.76

3.77


0.725

0.875

2017


52.00

80.00


64.00

85.71


3.27

4.02


0.750

0.875

2018


58.00

85.00


68.39

91.43


3.45

4.27


0.775

0.875

2019


64.00

90.00


73.75

97.14


3.63

4.53


0.800

0.875

2020


70.00

95.00


78.79

102.86


3.81

4.78


0.825

0.875

2021


75.00

98.54


82.35

106.18


3.90

5.03


0.850

0.875

2022


80.00

100.51


88.24

108.31


4.10

5.28


0.850

0.875

2023


85.00

102.52


94.12

110.47


4.30

5.53


0.850

0.875

2024


87.88

104.57


96.48

112.67


4.50

5.71


0.850

0.875

2025 (1)


89.63



98.41



4.60



0.850

0.875

Escalate thereafter at


+2% / year

+2% / year


+2% / year

+2% / year


+2% / year

+2% / year


0.850

0.875

(1)

Escalated at two per cent per year starting in 2025 in the January 1, 2016 GLJ price forecast with the exception of foreign exchange, which remains flat.

Table 2












Reserves Summary(1)


Crude and Tight
Oil(2)


NGLs


Natural Gas(3)


2015 Oil
Equivalent


2014 Oil
Equivalent

Company Gross


(Mbbl)


(Mbbl)


(MMcf)


(Mboe)


(Mboe)

Proved Producing


82,163


12,712


759,803


221,509


209,509

Proved Developed Non-Producing


2,913


870


49,679


12,062


20,164

Proved Undeveloped


13,784


15,470


783,010


159,755


152,390

Total Proved


98,860


29,052


1,592,492


393,327


382,063

Proved plus Probable


146,483(4)


53,343


2,922,145(5)


686,851


672,748

(1)

Amounts may not add due to rounding.

(2)

Crude and Tight Oil includes product types of light and medium crude oil, tight oil and heavy crude oil.

(3)

Natural Gas includes product types of shale gas and conventional natural gas.

(4)

Proved plus Probable Crude and Tight Oil closing balance by percentage weighting of product type: approximately 71 per cent light and medium crude oil, 28 per cent tight oil and one per cent heavy crude oil.

(5)

Proved plus Probable Natural Gas closing balance by percentage weighting of product type: approximately 96 per cent shale gas and four per cent conventional natural gas.

Table 3



















Reserves Reconciliation(1)


Crude and Tight
Oil(2)


NGLs


Natural Gas(3)


Oil Equivalent

Company Gross


(Mbbl)


(Mbbl)


(MMcf)


(Mboe)

Proved Producing










Opening Balance, January 1, 2015


87,990


12,136


656,299


209,509



Exploration Discoveries







Extensions and Improved Recovery (4)


6,168


1,756


239,384


47,821



Technical Revisions


7,279


1,946


91,908


24,544



Acquisitions


63




63



Dispositions


(3,839)


(183)


(52,114)


(12,708)



Economic Factors


(3,767)


(301)


(13,684)


(6,349)



Production


(11,731)


(2,642)


(161,990)


(41,372)


Ending Balance, December 31, 2015


82,163


12,712


759,803


221,509

Total Proved










Opening Balance, January 1, 2015


104,931


21,668


1,532,788


382,063



Exploration Discoveries







Extensions and Improved Recovery (4)


7,510


4,286


191,010


43,631



Technical Revisions


9,283


6,704


128,266


37,366



Acquisitions


63




63



Dispositions


(4,724)


(260)


(55,968)


(14,312)



Economic Factors


(6,472)


(705)


(41,614)


(14,113)



Production


(11,731)


(2,642)


(161,990)


(41,372)


Ending Balance, December 31, 2015


98,860


29,052


1,592,492


393,327

Proved plus Probable










Opening Balance, January 1, 2015


152,035


40,454


2,881,551


672,748



Exploration Discoveries







Extensions and Improved Recovery (4)


12,171


9,066


220,516


57,990



Technical Revisions


8,616


7,903


116,551


35,944



Acquisitions


80




80



Dispositions


(8,805)


(766)


(82,391)


(23,303)



Economic Factors


(5,882)


(672)


(52,092)


(15,236)



Production


(11,731)


(2,642)


(161,990)


(41,372)


Ending Balance, December 31, 2015


146,483(5)


53,343


2,922,145(6)


686,851

(1)

Amounts may not add due to rounding.

(2)

Crude and Tight Oil includes product types of light and medium crude oil, tight oil and heavy crude oil.

(3)

Natural Gas includes product types of shale gas and conventional natural gas.

(4)

Reserves additions for infill drilling, improved recovery, and extensions are combined and reported as "Extensions and Improved Recovery."

(5)

Proved plus Probable Crude and Tight Oil closing balance by percentage weighting of product type: approximately 71 per cent light and medium crude oil, 28 per cent tight oil and one per cent heavy crude oil.

(6)

Proved plus Probable Natural Gas closing balance by percentage weighting of product type: approximately 96 per cent shale gas and four per cent conventional natural gas.

Reserve Life Index

ARC's 2P RLI was 15.9 years at year-end 2015, while the proved RLI was 9.1 years based upon dividing the appropriate GLJ reserves category by ARC's 2016 production guidance midpoint of 118,000 boe per day, which is contingent upon the execution of a revised $390 million capital program for 2016. The 2P RLI has been maintained at greater than 15 years since year-end 2011, as a result of successful delineation and reserves growth of the Montney in northeast British Columbia. ARC's annual average production has increased from 73,954 boe per day in 2010 to 114,167 boe per day in 2015. The following table summarizes ARC's historical RLI.

Table 4








Reserve Life Index

2015 (1)


2014


2013


2012


2011

Total Proved

9.1


8.5


9.1


10.5


10.7

Proved plus Probable

15.9


15.0


15.5


17.5


17.0

(1)

Based on production guidance midpoint of 118,000 boe per day for 2016.

Net Present Value Summary

ARC's oil, natural gas and NGLs reserves were evaluated using GLJ's commodity price forecasts at January 1, 2016. The net present value ("NPV") is prior to provision for interest, debt service charges, and general and administrative expenses. It should not be assumed that the NPV of cash flow estimated by GLJ represents the fair market value of the reserves. The NPV of ARC's reserves decreased relative to year-end 2014 due to a reduction in the January 1, 2016 GLJ price forecast for both oil and natural gas as previously outlined in Table 1. NPVs on both a before- and after-tax basis are presented in Table 5.

Table 5












NPV of Cash Flow(1)(2)




Discounted


Discounted


Discounted


Discounted

($ millions)


Undiscounted


at 5%


at 10%


at 15%


at 20%

Before-tax








Proved Producing


4,670


3,289


2,533


2,064


1,748


Proved Developed Non-Producing


206


158


128


107


92


Proved Undeveloped


2,119


1,185


707


434


266


Total Proved


6,995


4,632


3,367


2,605


2,106


Probable


6,199


3,046


1,772


1,142


785


Proved plus Probable


13,194


7,678


5,139


3,748


2,891

After-tax(3)(4)








Proved Producing


4,030


2,906


2,279


1,885


1,615


Proved Developed Non-Producing


151


116


94


79


68


Proved Undeveloped


1,550


836


467


258


129


Total Proved


5,732


3,858


2,841


2,222


1,812


Probable


4,538


2,206


1,258


789


524


Proved plus Probable


10,269


6,063


4,098


3,011


2,336

(1)

Amounts may not add due to rounding.

(2)

Based on NI 51-101 net interest reserves and GLJ price forecasts and costs at January 1, 2016.

(3)

Based on ARC's estimated tax pools at year-end 2015.

(4)

The after-tax NPV of ARC's oil and natural gas properties reflects the tax burden on the properties on a standalone basis. It does not consider the business entity tax-level situation or tax planning, nor does it provide an estimate of the value at the level of the business entity, which may be significantly different. ARC's audited Consolidated Financial Statements and Notes and Management's Discussion & Analysis should be consulted for information at the business entity level.

At a 10 per cent discount factor, and on a before-tax basis, proved producing reserves constitute 75 per cent of the total proved reserves cash flow (NPV10 before-tax), while total proved reserves account for 66 per cent of the 2P reserves cash flow (NPV10 before-tax).

Future Development Capital

FDC reflects the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities, and changes in capital cost estimates based on improvements in well design and performance, as well as changes in service costs. FDC for total 2P reserves decreased to $2.7 billion at year-end 2015 from $3.6 billion at year-end 2014. The decrease in FDC in 2015 was predominantly attributed to the decrease in well and facility capital costs, the removal of capital associated with dispositions, and the removal of capital recognized at year-end 2014 that was executed in 2015.

Table 6 outlines GLJ estimated FDC required to bring total proved and total proved plus probable reserves on production.

Table 6





Future Development Capital (1)(2)




($ millions)

Total Proved


Total Proved plus Probable

2016

215


465

2017

358


515

2018

385


603

2019

236


377

2020

83


148

Remainder

210


623

Total FDC, Undiscounted

1,488


2,730

Total FDC, Discounted at 10%

1,127


1,982

(1)

Amounts may not add due to rounding.

(2)

FDC as per GLJ Independent Reserves Evaluation as of December 31, 2015 and based on GLJ forecast pricing at January 1, 2016.

Finding, Development and Acquisition Costs

ARC's 2015 F&D costs were $6.97 per boe and $8.20 per boe for 2P and proved reserves, respectively, excluding FDC (($2.82) per boe and $0.19 per boe, respectively, for 2P and proved reserves, including FDC). The downward change in FDC, which was greater than the 2015 capital spent, resulted in negative one-year 2P F&D costs, including FDC. Given the large reduction in FDC, one-year F&D costs, including FDC, are not meaningful. ARC's three-year average F&D costs were $10.36 per boe for 2P reserves and $14.13 per boe for proved reserves, excluding FDC. The low F&D costs are attributed to the high quality of ARC's portfolio of properties, strong results from ARC's development program, and meaningful reserves growth, notably at Tower, Sunrise and Dawson. ARC's 2015 F&D costs include approximately $6.7 million of spending on Crown lands, with no significant associated reserves or production associated with these acquisitions in the current year.

Including net acquisitions, ARC's 2015 Finding, Development and Acquisition ("FD&A") costs were $8.54 per boe for 2P reserves and $9.00 per boe for proved reserves, excluding FDC (($7.80) per boe and ($2.20) per boe, respectively, for 2P and proved reserves, including FDC). The three-year average FD&A costs were $11.88 per boe for 2P reserves and $15.98 per boe for proved reserves, excluding FDC. ARC's low FD&A costs reflect ARC's focus on high-quality assets, cost management, and allocation of resources and capital to high rate of return projects. ARC's 2015 FD&A costs include approximately $6.7 million of spending on Crown lands, with no significant associated reserves or production. There was no capital spending on acquisition of facilities or infrastructure, or on lands with significant associated reserves or production during 2015. Additionally, ARC's FD&A costs incorporate the net disposition of properties with associated reserves and production for approximately $74 million in 2015.

Table 7 highlights ARC's reserves, F&D costs, FD&A costs and the associated recycle ratios for the past three years.

Table 7







Reserves (Company Gross), Capital Expenditures and Operating







Netbacks(1)(2)


2015


2014


2013

Reserves(Mboe)






Proved Producing


221,509


209,509


208,454


Total Proved


393,327


382,063


373,976


Proved plus Probable


686,851


672,748


633,864

Capital Expenditures($ millions)






Exploration and Development


548.3


1,007.8


874.2


Net Acquisitions and (Dispositions)


(74.4)


34.2


(53.4)


Total Capital Expenditures


473.9


1,042.0


820.8

Operating Netbacks($/boe)






Operating Netback


16.69


33.01


28.57


Operating Netback – Three-Year Average


25.91


28.86


27.24

(1)

Amounts may not add due to rounding.

(2)

Operating netback is calculated using production revenues, excluding realized gains and losses on commodity hedging, less
royalties, transportation and operating expenses, calculated on a per boe equivalent basis.

Table 7a





Finding and Development Costs, excluding FDC(1)(2)(3)(4)




Company Gross

2015


2014


2013

Proved Producing





Reserve Additions (MMboe)

66.0


48.0


47.4



F&D Costs ($/boe)

8.31


20.99


18.43



F&D Recycle Ratio

2.0


1.6


1.6



F&D Costs – Three-Year Average ($/boe)

15.05


20.49


20.24



F&D Recycle Ratio – Three-Year Average

1.7


1.4


1.3

Total Proved





Reserve Additions (MMboe)

66.9


55.0


50.1



F&D Costs ($/boe)

8.20


18.32


17.45



F&D Recycle Ratio

2.0


1.8


1.6



F&D Costs – Three-Year Average ($/boe)

14.13


17.32


14.18



F&D Recycle Ratio – Three-Year Average

1.8


1.7


1.9

Proved plus Probable





Reserve Additions (MMboe)

78.7


87.5


68.4



F&D Costs ($/boe)

6.97


11.51


12.79



F&D Recycle Ratio

2.4


2.9


2.2



F&D Costs – Three-Year Average ($/boe)

10.36


11.15


8.24



F&D Recycle Ratio – Three-Year Average

2.5


2.6


3.3

(1)

In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures by the
applicable reserves additions both before and after changes in FDC costs.

(2)

Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis.

(3)

Recycle ratio is defined as operating netback per barrel of oil equivalent divided by the appropriate F&D or FD&A costs on a per barrel
of oil equivalent.

(4)

The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated
future development costs may not reflect the total F&D costs related to reserves additions for that year.

Table 7b






Finding and Development Costs, including FDC(1)(2)(3)(4)





Company Gross

2015


2014


2013

Proved Producing






Change in FDC ($ millions)

(53.5)


32.9


42.0


Reserve Additions (MMboe)

66.0


48.0


47.4



F&D Costs ($/boe)

7.49


21.68


19.32



F&D Recycle Ratio

2.2


1.5


1.5



F&D Costs – Three-Year Average ($/boe)

15.19


21.09


20.60



F&D Recycle Ratio – Three-Year Average

1.7


1.4


1.3

Total Proved






Change in FDC ($ millions)

(535.6)


69.6


33.0


Reserve Additions (MMboe)

66.9


55.0


50.1



F&D Costs ($/boe)

0.19


19.58


18.11



F&D Recycle Ratio

87.8


1.7


1.6



F&D Costs – Three-Year Average ($/boe)

11.61


18.81


17.42



F&D Recycle Ratio – Three-Year Average

2.2


1.5


1.6

Proved plus Probable






Change in FDC ($ millions)

(770.3)


333.5


(90.2)


Reserve Additions (MMboe)

78.7


87.5


68.4



F&D Costs ($/boe)

(2.82)


15.32


11.47



F&D Recycle Ratio

(5.9)


2.2


2.5



F&D Costs – Three-Year Average ($/boe)

8.11


13.34


12.01



F&D Recycle Ratio – Three-Year Average

3.2


2.2


2.3

(1)

The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed
reserves into production. In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures by the
applicable reserves additions both before and after changes in FDC costs.

(2)

Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis.

(3)

Recycle ratio is defined as operating netback per barrel of oil equivalent divided by the appropriate F&D or FD&A costs on a per
barrel of oil equivalent.

(4)

The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated
future development costs may not reflect the total F&D costs related to reserves additions for that year.

Table 7c





Finding, Development and Acquisition Costs, excluding FDC(1)(2)(3)(4)




Company Gross

2015


2014


2013

Proved Producing





Reserve Additions, including Net Acquisitions (Dispositions) (MMboe)

53.4


41.7


42.2



FD&A Costs ($/boe)

8.88


24.97


19.46



FD&A Recycle Ratio

1.9


1.3


1.5



FD&A Costs – Three-Year Average ($/boe)

17.02


22.77


21.53



FD&A Recycle Ratio – Three-Year Average

1.5


1.3


1.3

Total Proved





Reserve Additions, including Net Acquisitions (Dispositions) (MMboe)

52.6


48.8


44.8



FD&A Costs ($/boe)

9.00


21.37


18.31



FD&A Recycle Ratio

1.9


1.5


1.6



FD&A Costs – Three-Year Average ($/boe)

15.98


18.99


15.00



FD&A Recycle Ratio – Three-Year Average

1.6


1.5


1.8

Proved plus Probable





Reserve Additions, including Net Acquisitions (Dispositions) (MMboe)

55.5


79.6


61.6



FD&A Costs ($/boe)

8.54


13.10


13.32



FD&A Recycle Ratio

2.0


2.5


2.1



FD&A Costs – Three-Year Average ($/boe)

11.88


11.94


8.39



FD&A Recycle Ratio – Three-Year Average

2.2


2.4


3.2

(1)

In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures by the
applicable reserves additions both before and after changes in FDC costs.

(2)

Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis.

(3)

Recycle ratio is defined as operating netback per barrel of oil equivalent divided by the appropriate F&D or FD&A costs on a per
barrel of oil equivalent.

(4)

The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated
future development costs may not reflect the total F&D costs related to reserves additions for that year.

Table 7d





Finding, Development and Acquisition Costs, including FDC(1)(2)(3)(4)




Company Gross

2015


2014


2013

Proved Producing





Change in FDC ($ millions)

(63.4)


31.0


41.6


Reserve Additions, including Net Acquisitions (Dispositions) (MMboe)

53.4


41.7


42.2



FD&A Costs ($/boe)

7.69


25.71


20.44



FD&A Recycle Ratio

2.2


1.3


1.4



FD&A Costs – Three-Year Average ($/boe)

17.09


23.41


21.93



FD&A Recycle Ratio – Three-Year Average

1.5


1.2


1.2

Total Proved





Change in FDC ($ millions)

(589.5)


69.2


38.9


Reserve Additions, including Net Acquisitions (Dispositions) (MMboe)

52.6


48.8


44.8



FDA& Costs ($/boe)

(2.20)


22.79


19.18



FD&A Recycle Ratio

(7.6)


1.4


1.5



FD&A Costs – Three-Year Average ($/boe)

12.69


20.74


18.57



FD&A Recycle Ratio – Three-Year Average

2.0


1.4


1.5

Proved plus Probable





Change in FDC ($ millions)

(906.2)


333.2


(76.7)


Reserve Additions, including Net Acquisitions (Dispositions) (MMboe)

55.5


79.6


61.6



FD&A Costs ($/boe)

(7.80)


17.29


12.07



FD&A Recycle Ratio

(2.1)


1.9


2.4



FD&A Costs – Three-Year Average ($/boe)

8.58


14.44


12.47



FD&A Recycle Ratio – Three-Year Average

3.0


2.0


2.2

(1)

The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed
reserves into production. In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures by the
applicable reserves additions both before and after changes in FDC costs.

(2)

Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis.

(3)

Recycle ratio is defined as operating netback per barrel of oil equivalent divided by the appropriate F&D or FD&A costs on a per
barrel of oil equivalent.

(4)

The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated
future development costs may not reflect the total F&D costs related to reserves additions for that year.

NE BC MONTNEY RESOURCES EVALUATION

The following discussion in "NE BC Montney Resources Evaluation" is subject to a number of cautionary statements, assumptions and risks as set forth therein. See "Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information" at the end of this release for additional cautionary language, explanations and discussion, and see "Forward-looking Statements" for a statement of principal assumptions and risks that may apply. See also "Definitions of Oil and Gas Resources and Reserves" in this news release. The discussion includes reference to TPIIP, DPIIP and Economic Contingent Resource ("ECR") as per the GLJ Resources Evaluation as at December 31, 2015, prepared in accordance with the COGE Handbook. Unless otherwise indicated in this news release, all references to ECR and Prospective volumes are Best Estimate ECR and Best Estimate Prospective volumes, respectively.

Amendments to NI 51-101 that came into effect on July 1, 2015 require significant changes to the way resources are disclosed relative to prior years. The most significant changes require:

  • The classification of contingent resources into the following specified project maturity subclasses. Those that apply to ARC's resources include:
    • Development pending
    • Development unclarified
    • Development not viable
  • Changes to the product types, including the addition of new product types and providing new definitions for some existing product types;
  • The disclosure of the risked, best estimate of the contingent resources volumes for each product type;
  • The disclosure of the risked NPV of future net revenues for any disclosed development pending contingent resources, calculated using forecast prices and costs for each product type, on a before- and after-tax basis using discount rates of zero per cent, five per cent, 10 per cent, 15 per cent and 20 per cent;
  • The disclosure of the chance of development risk for each project maturity sub-class the issuer discloses; and
  • The disclosure of the estimated total cost to achieve commercial production, the estimated date of first commercial production and the recovery technology to be used.

The Montney formation in northeast British Columbia and Alberta has been identified as a world-class unconventional natural gas resource play with the potential for significant volumes of recoverable resources. The area includes dry gas, liquids-rich gas and tight oil development opportunities. It is one of the largest and lowest cost natural gas resource plays in North America. ARC has a significant presence in northeast British Columbia and across the provincial border at Pouce Coupe, with a land position of 728 net sections, located primarily in the most prospective areas of the play.

GLJ was commissioned to conduct an Independent Resources Evaluation for ARC's lands in the NE BC Montney region, including Dawson, Parkland/Tower, Sunrise/Sunset, Sundown, Septimus, Attachie, Red Creek, and Blueberry in northeast British Columbia, and Pouce Coupe just across the provincial border in Alberta (the "Evaluated Areas"). The Resources Evaluation was effective December 31, 2015 based on GLJ forecast pricing at January 1, 2016. All references in the following discussion to TPIIP, Discovered Petroleum Initially in Place ("DPIIP") and ECR are in reference to the Evaluated Areas included in the Independent Resources Evaluation. The results of the 2015 and 2014 resources evaluations are summarized in the discussion and tables below.

The evaluation reaffirmed that ARC's NE BC Montney assets provide a significant long-term growth opportunity with considerable potential reserves, extending well beyond existing booked reserves and even the current estimates of the ECR. ARC's NE BC Montney assets provide optionality for future growth through commodity price cycles given the diversity of ARC's Montney landholdings with exposure to liquids-rich natural gas, crude oil and dry natural gas. ARC believes that the concentrated nature of the assets will result in additional upside based on expected capital efficiencies.

ARC's 2015 capital development program was primarily focused on Montney development, which was inclusive of crude oil, liquids-rich gas and dry gas opportunities. In northeast British Columbia, ARC's capital development program consisted of drilling 48 gross operated wells (48 net wells), comprised of 22 tight oil wells at Tower, five liquids-rich wells (three wells at Attachie and two wells at Parkland) and 21 shale gas wells (14 wells at Sunrise and seven wells at Dawson).

TPIIP for the shale gas-bearing lands in the Evaluated Areas increased 34 per cent relative to 2014 to 90 Tcf. The 2015 drilling program resulted in a 17 per cent increase of DPIIP for the Evaluated Areas to 41.4 Tcf. Growth in shale gas TPIIP and DPIIP is primarily attributed to 2015 land acquisition activity in Sunrise and Attachie.

Shale gas ECR was evaluated on an unrisked and risked basis in 2015 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending shale gas ECR totaled 2.4 Tcf and risked development unclarified shale gas ECR totaled 3.3 Tcf. The risked prospective shale gas ECR totaled 5.3 Tcf.

NGLs ECR was also evaluated on an unrisked and risked basis in 2015 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending NGLs ECR totaled 36.9 MMbbl and risked development unclarified NGLs ECR totaled 201 MMbbl. The risked prospective NGLs ECR totaled 319 MMbbl.

On the tight oil-bearing lands at Tower, Red Creek and Attachie, TPIIP increased 315 per cent to 9,688 MMbbl and DPIIP increased 217 per cent to 5,736 MMbbl. The increase in tight oil TPIIP and DPIIP is attributed to land acquisition activity at Attachie as well as the conversion of the 2014 classification of Attachie East lands, from a gas resource to an oil resource in the Upper Montney formation.

Tight Oil ECR was evaluated on an unrisked and risked basis in 2015 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending tight oil ECR totaled 33 MMbbl and risked development unclarified tight oil ECR totaled 129 MMbbl. The risked prospective tight oil ECR totaled 81 MMbbl.

Risking of the contingent resources included a quantitative assessment of the economic status, the recovery technology status, the project evaluation scenario status, and the development time frame. Risking of the prospective resources included a quantitative assessment of these same factors, as wells as a quantitative assessment of the chance of discovery.

Table 8






Shale Gas Resources (1)(2)(3)(4)





(Tcf)


2015


2014

Total Petroleum Initially in Place


90.0


67.4

Discovered Petroleum Initially in Place


41.4


35.4

Undiscovered Petroleum Initially in Place ("UPIIP")


48.6


32.0

(1)

TPIIP, DPIIP and UPIIP have been estimated using a one per cent porosity cut-off in both 2015 and 2014, which means that essentially all gas-bearing rock has been incorporated into the calculations.

(2)

The resource categories in this table do not include free crude oil or liquids.

(3)

All volumes listed in the table are company gross and raw gas volumes.

(4)

All numbers are "Best Estimates."

Table 9






Tight Oil Resources (1)(2)(3)(4)





(MMbbl)


2015


2014

Total Petroleum Initially in Place


9,688


2,334

Discovered Petroleum Initially in Place


5,736


1,807

Undiscovered Petroleum Initially in Place


3,952


527

(1)

TPIIP, DPIIP and UPIIP have been estimated using a three per cent porosity cut-off for tight oil due to lower mobility for oil relative to gas.

(2)

All volumes listed in the table are company gross.

(3)

The tight oil DPIIP is a Stock Tank Barrel.

(4)

All numbers are "Best Estimates."

Table 10








2015 Reserves and Risked and Unrisked ECR (1)(2)(3)(4)(5)


Chance of
Development


Best Estimate
Unrisked


Best Estimate
Risked

Shale Gas (Tcf)








Reserves


100 %


2.6


2.6


Development Pending ECR


92 %


2.6


2.4


Development Unclarified ECR


76 %


4.4


3.3

NGLs (MMbbl)








Reserves


100 %


42.3


42.3


Development Pending ECR


94 %


39.1


36.9


Development Unclarified ECR


76 %


265.1


200.9

Tight Oil (MMbbl)








Reserves


100 %


22.7


22.7


Development Pending ECR


95 %


34.8


33.1


Development Unclarified ECR


79 %


163.2


129.0

(1)

All DPIIP, other than cumulative production, reserves, and ECR, has been categorized as unrecoverable. Cumulative raw production to year-end 2015 was 0.6 Tcf of shale gas and 2.5 MMbbl of tight oil, all of which are immaterial in relation to the reserves and ECR magnitude. NGLs cumulative production is calculated based on current NGLs recoveries.

(2)

All volumes listed in the table are company gross and sales volumes.

(3)

All numbers are "Best Estimates."

(4)

All ECR have been risked for chance of development. For ECR, the chance of development is defined as the probability of a project being commercially viable. In quantifying the chance of development, factors that were assessed quantitatively to be less than one in the risking calculation included the economic status, the project evaluation scenario status, and the development time frame. The chance of development is multiplied by the unrisked resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of development is an uncertain value that should be used with caution.

(5)

For reserves, the volumes under the heading "Best Estimate" are 2P reserves.

An estimate of risked NPV of future net revenues of the development pending contingent resources subclass only is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of ARC proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked NPV of future net revenue will be realized. The other subclasses of resources are not included in this NPV and therefore this is not reflective of the value of the resource base.

Table 11








2015 Risked and Unrisked ECR

Development Pending (1)(2)(3)


Chance of
Development


Best Estimate
Unrisked


Best Estimate
Risked

Shale Gas (Tcf)


92 %


2.6


2.4

NGLs (MMbbl)


94 %


39.1


36.9

Tight Oil (MMbbl)


95 %


34.8


33.1

Before-tax NPV ($ millions)








Undiscounted




10,624


9,890


Discounted at 5%




3,447


3,203


Discounted at 10%




1,247


1,154


Discounted at 15%




443


406


Discounted at 20%




114


100

After-tax NPV ($ millions)








Undiscounted




7,728


7,194


Discounted at 5%




2,431


2,258


Discounted at 10%




812


750


Discounted at 15%




229


208


Discounted at 20%




(3)


(8)

(1)

All volumes listed in the table are company gross and sales volumes.

(2)

NPV as per GLJ Independent Resources Evaluation as of December 31, 2015 and based on GLJ forecast pricing at January 1, 2016.

(3)

Risk in the above table is the chance of development. Contingent resources are discovered resources by definition.

The estimated cost to bring on commercial production the Development Pending Contingent Resources for all three product types is approximately $3.8 billion (discounted at 10 per cent is approximately $1.5 billion). The expected timeline to bring these resources onto production is between two and 10 years. The ECR are expected to be recovered using the same technology in horizontal drilling and multi-stage fracturing that ARC has already proven to be effective in the Montney in northeast British Columbia.

Table 12








2015 Prospective Resources (1)(2)(3)(4)


Chance of
Commerciality


Best Estimate
Unrisked


Best Estimate
Risked

Shale Gas (Tcf)


49 %


10.7


5.3

NGLs (MMbbl)


46 %


690.8


319.3

Tight Oil (MMbbl)


68 %


119.0


81.3

(1)

All UPIIP, other than prospective resources, has been categorized as unrecoverable. GLJ estimated DPIIP values using a porosity cut-off of one per cent for shale gas and three per cent for tight oil.

(2)

All volumes listed in the table are company gross and sales volumes.

(3)

Prospective resources have been risked for chance of development and chance of discovery. For prospective resources, the chance of development multiplied by the chance of discovery is defined as the probability of a project being commercially viable. In quantifying the chance of commerciality, factors that were assessed quantitatively to be less than one in the risking calculation included the economic status, the project evaluation scenario status and the development time frame, along with the overall chance of discovery. The chance of commerciality is multiplied by the unrisked prospective resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of commerciality is an uncertain value that should be used with caution.

(4)

All prospective resources are subclassified as the prospective maturity subclass.

Based upon the foregoing analysis, as well as ARC's expertise in the Montney formation in northeast British Columbia, it is expected that significant additional reserves will be developed in the future with continued drilling success on currently undeveloped Montney acreage, together with further development, completions refinements and improved economic conditions. Historic drilling success and recoveries on the more fully developed Montney acreage, abundant well log and production test data, and the application of increased drilling densities, support ARC's belief that significant additional resources will be recovered. Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop the resources, low commodity prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, and the effectiveness of fracing technology and applications. For ECR to be converted to reserves, Management and the Board need to ascertain commercial production rates, then develop firm plans, including timing, infrastructure, and the commitment of capital. Confirmation of commercial productivity is generally required before the Company can prepare firm development plans and commit required capital for the development of the ECR. Additional contingencies are related to the current lack of infrastructure required to develop the resources in a relatively quick time frame. As continued delineation occurs, some resources currently classified as ECR are expected to be re-classified to reserves.

DEFINITIONS OF OIL AND GAS RESOURCES AND RESERVES


Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:




Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.




Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.




Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.



Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total Resources" is equivalent to "Total Petroleum Initially-In-Place." Resources are classified in the following categories:




Total Petroleum Initially-In-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.




Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves, and contingent resources; the remainder is unrecoverable.




Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.




Economic Contingent Resources ("ECR") are those contingent resources which are currently economically recoverable.




Project Maturity Subclass Development Pending is defined as a contingent resource that has been assigned a high chance of development and the resolution of final conditions for development are being actively pursued.




Project Maturity Subclass Development Unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until contingencies can be clearly defined.




Undiscovered Petroleum Initially-In-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of UPIIP is referred to as "prospective resources" and the remainder as "unrecoverable."




Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.




Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.




Uncertainty Ranges are described by the COGE Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 per cent probability that the quantities actually recovered will equal or exceed the best estimate.

INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES, RESOURCES AND OPERATIONAL INFORMATION

All amounts in this news release are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent ("boe") based on a six Mcf to one barrel ratio. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip, and given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of boe in isolation may be misleading. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, and without including any royalty interest, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on company gross reserves using forecast prices and costs.

This press release contains metrics commonly used in the oil and natural gas industry, such as "recycle ratio," "finding and development costs," "finding and development recycle ratio," "finding, development and acquisition costs," "operating netbacks," and "reserve life index." These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total F&D costs related to reserves additions for that year. F&D costs both including and excluding acquisitions and dispositions have been presented in this news release because acquisitions and dispositions can have a significant impact on ARC's ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of its cost structure. Recycle ratio is measured by dividing the operating netback by appropriate F&D or FD&A costs per boe for the year. Operating netback is calculated using production revenues, excluding realized gains and losses on commodity hedging, less royalties, transportation and operating expenditures, calculated on a per boe equivalent basis. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare ARC's performance over time.

ARC's oil and gas reserves statement for the year ended December 31, 2015, which will include complete disclosure of its oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within ARC's AIF which will be available on or before March 30, 2016 on ARC's website at www.arcresources.com and on SEDAR at www.sedar.com.

This news release contains references to estimates of oil and gas classified as TPIIP, DPIIP, UPIIP and ECR in the Montney region in northeast British Columbia, including lands in Pouce Coupe in Alberta, which are not, and should not be confused with, oil and gas reserves. See "Definitions of Oil and Gas Resources and Reserves."

Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, ARC's policy of orderly development on a staged basis, the timing of the growth of third-party infrastructure, the short- and long-term view of ARC on gas prices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints.

ARC's belief that it will establish significant additional reserves over time with conversion of DPIIP into ECR, ECR into 2P reserves, and probable reserves into proved reserves, is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading "Forward-looking Information and Statements."

Notice to US Readers

The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission ("the SEC") generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves (as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves (which are defined differently from the SEC rules) but also probable reserves, each as defined in NI 51-101. Accordingly, proved reserves disclosed in this news release may not be comparable to US standards, and in this news release, ARC has disclosed reserves designated as "probable reserves" and "proved plus probable reserves." Probable reserves are higher-risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. The SEC's guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with US disclosure requirements. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalties and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Moreover, ARC has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. As a consequence of the foregoing, ARC's reserve estimates and production volumes in this news release may not be comparable to those made by companies utilizing United States reporting and disclosure standards. Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose resource volumes. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, resources, see above.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect," "anticipate," "continue," "estimate," "objective," "ongoing," "may," "will," "project," "should," "believe," "plans," "intends," "strategy," and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves under the heading "2015 Independent Reserves Evaluation" and the recognition of significant resources under the heading "NE BC Montney Resources Evaluation," the volumes and estimated value of ARC's oil and gas reserves; the life of ARC's reserves; the volume and product mix of ARC's oil and gas production; future oil and natural gas prices; future results from operations and operating metrics; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations.

The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities are consistent with past results; the continued and timely development of infrastructure in areas of new production; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserve and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures. There are a number of assumptions associated with the development of the Evaluated Areas, including the quality of the Montney reservoir, continued performance from existing wells, future drilling programs and performance from new wells, the growth of infrastructure, well density per section, and recovery factors and development necessary involves known and unknown risks and uncertainties, including those risks identified in this news release. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; the early stage of development of some areas in the Evaluated Areas; the potential for variation in the quality of the Montney formation, changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; unanticipated results from ARC's exploration and development activities; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third-party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's AIF).

The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

ARC Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $6.8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

Myron M. Stadnyk
President and Chief Executive Officer

SOURCE ARC Resources Ltd.

For further information: about ARC Resources Ltd., please visit our website www.arcresources.com; or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6427, Toll Free 1-888-272-4900, ARC Resources Ltd., Suite 1200, 308 - 4th Avenue SW, Calgary, AB, T2P 0H7


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