ARC Resources Ltd. announces 210 per cent produced reserves replacement in 2014

CALGARY, Feb. 11, 2015 /CNW/ - (ARX – TSX) ARC Resources Ltd. ("ARC") released today its 2014 year-end reserves and resources information.

"Our team delivered another year of exceptional results, replacing 210 per cent of production through the drill bit at low finding and development costs.  Our Montney assets were the centerpiece of reserves and resources growth in 2014, a testament to the high quality assets in our portfolio.  Our low finding and development costs reflect the success of our strategy to grow our efficient, low cost Montney business.  We are well positioned with a strong balance sheet, world class assets and a focus on profitability as we pursue our long-term vision of creating value for our shareholders through all commodity price cycles." stated Myron Stadnyk, President and CEO

HIGHLIGHTS

  • Replaced approximately 210 per cent of 2014 total production, adding 87.5 MMboe of proved plus probable ("2P") reserves through development capital activities.  This is the seventh consecutive year that ARC has delivered 200 per cent or greater produced reserves replacement.
  • Six per cent increase in 2P reserves to 673 MMboe, comprised of 2.9 Tcf of natural gas and 192 MMbbls of crude oil and natural gas liquids ("NGL's") at year-end 2014
  • Replaced 300 per cent of 2014 gas production, adding 0.4 Tcf of 2P gas reserves.  ARC's gas development resulted in a nine per cent increase in 2P gas reserves from 2.6 Tcf to 2.9 Tcf. Material reserves growth was realized in the Northeast British Columbia ("NE B.C.") Montney region, particularly in Parkland/Tower, Sunrise and Septimus.
  • Replaced approximately 90 per cent of 2014 crude oil and NGL production, adding 14 MMbbls of 2P crude oil and NGL's reserves
  • Finding and Development costs ("F&D") of $11.51 per boe for 2P reserves and $18.32 per boe for proved reserves, excluding Future Development Capital ("FDC").  Significant NE B.C. Montney reserve additions contributed to the ten per cent decrease in 2P F&D costs relative to 2013. 
  • Strong RLI of 15.0 years, down slightly from 15.5 years at year-end 2013 as a result of production growth in 2014
  • 2P F&D, including FDC, of $15.32 for 2014 and $13.34 for the three year average. Proved F&D including FDC, was $19.58 for 2014 and $18.81 for the three year average.
  • Recycle ratio of 2.9 times and 2.6 times for the current year and three year average, respectively, for 2P reserves based on current and three year average F&D, excluding FDC (2.2 recycle ratio for both the current year and three year average, including FDC) based on current and three year average netbacks of $33.01 per boe and $28.86 per boe, respectively.
  • ARC updated an Independent Resources Evaluation ("Resources Evaluation" or "Independent Resources Evaluation") for its Montney lands in the northeast British Columbia ("NE B.C.") Montney region including lands at Pouce Coupe across the provincial border.  The updated evaluation realized a significant increase in the identified resource base on ARC's NE B.C. Montney lands. The natural gas Total Petroleum Initially In Place ("TPIIP") increased  22 per cent from 55.1 Tcf in 2013 to 67.4 Tcf in 2014 and oil TPIIP increased seven per cent to 2.3 billion barrels of oil from 2.2 billion barrels in 2013.(1)

(1)

Year-end 2014 complies with current COGE Handbook.  Resource Evaluation values provided are the best estimate case.  Year-end 2014 TPIIP estimate utilizes a 1% porosity cut-off for natural gas based on "Best Estimate" case.  Year-end 2013 TPIIP estimate utilized a 0% porosity cut-off for natural gas.  Estimates for both 2014 and 2013 were determined using a 3% porosity cut-off for oil based on "Best Estimate" case.



2014 INDEPENDENT RESERVES EVALUATION

GLJ Petroleum Consultants ("GLJ") conducted an independent reserves evaluation effective December 31, 2014 which was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("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, 2015 as outlined in Table 1 below.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without inclusion of any royalty interests) unless noted otherwise.  All reserves information has been prepared in accordance with NI 51-101.  This news release contains several cautionary statements that are specifically required by NI 51-101 under the heading "Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information".  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, 2014.

Based on this independent reserves evaluation, ARC's reserves profile as at December 31, 2014 is summarized below:

  • Six per cent increase in 2014 2P reserves to 673 MMboe compared to 634 MMboe of 2P reserves at year-end 2013 
  • 87.5 MMboe of 2P reserve additions from exploration and development activities (including revisions) before divestments and 2014 production of 41.0 MMboe (79.6 MMboe after 8.0 MMboe of net divestments)
  • 210 per cent replacement of 2P reserves based on 87.5 MMboe of 2P reserve additions and 2014 production of 41.0 MMboe.
  • Total proved reserves account for 57 per cent of 2P reserves
  • Proved developed producing reserves represent 55 per cent of total proved reserves and 31 per cent of 2P reserves
  • Crude oil and NGL's comprise 29 per cent of 2P reserves and natural gas comprises 71 per cent of 2P reserves on a 6:1 BOE conversion basis
  • Positive technical revisions of ten MMboe (2P) were realized, predominantly in Parkland/Tower, Sunrise, Septimus, Dawson and Ante Creek, reflecting the strength of ARC's Montney assets

Table 1





GLJ January 1, 2015

and 2014

Price Forecast

West Texas

Intermediate

Crude Oil

($US/bbl)

Edmonton

Light Crude Oil

($Cdn/bbl)

Natural Gas

at AECO

($Cdn/MMBtu)

Foreign Exchange

($US/$Cdn)


2015

2014

2015

2014

2015

2014

2015

2014

2015

62.50

97.50

64.71

97.37

3.31

4.26

0.850

0.95

2016

75.00

97.50

80.00

100.00

3.77

4.50

0.875

0.95

2017

80.00

97.50

85.71

100.00

4.02

4.74

0.875

0.95

2018

85.00

97.50

91.43

100.00

4.27

4.97

0.875

0.95

2019

90.00

97.50

97.14

100.00

4.53

5.21

0.875

0.95

2020

95.00

98.54

102.86

100.77

4.78

5.33

0.875

0.95

2021

98.54

100.51

106.18

102.78

5.03

5.44

0.875

0.95

2022

100.51

102.52

108.31

104.83

5.28

5.55

0.875

0.95

2023

102.52

104.57

110.47

106.93

5.53

5.66

0.875

0.95

2024 (1)

104.57

+2.0%/yr

112.67

+2.0%/yr

5.71

+2.0%/yr

0.875

0.95

Escalate thereafter at

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

0.875

0.95

(1)

Escalated at two per cent per year starting in 2024 in the January 1, 2014 GLJ price forecast with the exception of foreign exchange.

Table 2








RESERVES SUMMARY

Light and

Medium

Crude Oil

(Mbbl)

Heavy

Crude Oil

(Mbbl)

Total

Crude Oil

(Mbbl)

NGLs

(Mbbl)

 Natural

Gas

(Bcf)

Oil

Equivalent

2014

(Mboe)

Oil

Equivalent

2013

(Mboe)

Company Gross








Proved Producing

86,543

1,447

87,990

12,136

656

209,509

208,454

Proved Developed Non-producing

1,645

0

1,645

700

107

20,164

7,383

Proved Undeveloped

15,191

105

15,296

8,833

770

152,390

158,139

Total Proved

103,379

1,552

104,931

21,668

1,533

382,063

373,976

Proved plus Probable

150,003

2,032

152,035

40,454

2,882

672,748

633,864

Table 3








Light and 







Medium 

Heavy




Oil

RESERVES RECONCILIATION

Crude 

Crude Oil

Total Crude

NGLs

Natural

Equivalent

COMPANY GROSS

Oil (Mbbl) 

(Mbbl)

Oil(Mbbl)

(Mbbl)

Gas (MMcf)

(Mboe)

PROVED PRODUCING







Opening Balance

88,620

1,503

90,123

11,074

643,539

208,453


Exploration Discoveries

0

0

0

0

0

0


Extensions and Improved Recovery(1)

8,953

39

8,992

2,943

173,203

40,802


Technical Revisions

1,549

139

1,688

1,125

35,512

8,733


Acquisitions

409

0

409

16

811

560


Dispositions

-49

-13

-62

-1

-40,640

-6,836


Economic Factors

-59

-18

-77

-43

-8,432

-1,525


Production

-12,880

-203

-13,083

-2,978

-147,694

-40,677

Closing Balance

86,543

1,447

87,990

12,136

656,299

209,509

TOTAL PROVED







Opening Balance

108,894

1,686

110,580

21,383

1,452,079

373,976


Exploration Discoveries

0

0

0

0

0

0


Extensions and Improved Recovery (1)

5,772

0

5,772

2,889

203,543

42,585


Technical Revisions

2,392

100

2,492

612

80,369

16,499


Acquisitions

420

0

420

16

817

572


Dispositions

-49

-13

-62

-1

-40,640

-6,836


Economic Factors

-1,170

-18

-1,188

-253

-15,686

-4,055


Production

-12,880

-203

-13,083

-2,978

-147,694

-40,677

Closing Balance

103,379

1,552

104,931

21,668

1,532,788

382,063

PROVED PLUS PROBABLE







Opening Balance 

153,028

2,154

155,182

38,882

2,638,799

633,864


Exploration Discoveries

0

0

0

0

0

0


Extensions and Improved Recovery(1)

9,204

0

9,204

6,024

392,347

80,619


Technical Revisions

659

107

767

-1,207

62,183

9,923


Acquisitions

531

0

531

20

1,065

729


Dispositions

-70

-19

-89

-1

-51,667

-8,701


Economic Factors

-469

-7

-476

-286

-13,482

-3,009


Production

-12,880

-203

-13,083

-2,978

-147,694

-40,677

Closing Balance

150,003

2,032

152,035

40,454

2,881,551

672,748

(1)

Reserves additions for Infill Drilling, Improved Recovery and Extensions are combined and reported as "Extensions and Improved Recovery".

RESERVE LIFE INDEX ("RLI")

ARC's 2P RLI was 15.0 years at year-end 2014 while the proved RLI was 8.5 years based upon the GLJ reserves and ARC's 2015 production guidance mid-point of 122,500 boe per day, which is contingent upon the execution of a $750 million capital program. The increase in the 2P RLI from 2010 through 2012 was attributed to the successful delineation of the Montney in NE B.C. and the resulting growth in 2P reserves, while the subsequent decrease from the peak in 2012 is attributable to the successful development of the Montney region and increased production.  ARC's annual average production increased from 73,954 boe per day in 2010 to 112,387 boe per day in 2014.  The following table summarizes ARC's historical RLI.

Table 4






Reserve Life Index

2014 (1)

2013

2012

2011

2010

Total Proved

8.5

9.1

10.5

10.7

10.4

Proved Plus Probable

15.0

15.5

17.5

17.0

15.1

(1)

Based on production guidance midpoint of 122,500 boe per day for 2015.

NET PRESENT VALUE ("NPV") SUMMARY

ARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's commodity price forecasts effective January 1, 2015.  The 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 2013 due to a reduction in the January 1, 2015 GLJ price forecast for both crude oil and natural gas as outlined in Table 1.  NPVs on both a before and after tax basis are presented below.

Table 5






NPV of Cash Flow (1)

$ Millions

Undiscounted

Discounted

 at 5%

 Discounted

 at 10%

Discounted

 at 15%

Discounted

at 20%

Before Tax (BT)






Proved Producing

5,838

4,047

3,105

2,530

2,143

Proved Developed Non-Producing

392

266

200

159

132

Proved Undeveloped

2,073

1,036

510

213

32

Total Proved

8,303

5,350

3,815

2,902

2,308

Probable

7,521

3,623

2,093

1,352

940

Proved plus Probable

15,823

8,973

5,907

4,254

3,248

After Tax (AT) (2)(3)






Proved Producing

4,995

3,536

2,757

2,274

1,946

Proved Developed Non-Producing

292

198

147

117

97

Proved Undeveloped

1,545

726

307

70

-74

Total Proved

6,832

4,460

3,211

2,461

1,969

Probable

5,604

2,667

1,512

954

645

Proved plus Probable

12,436

7,127

4,723

3,415

2,614

(1)

Based on NI-51-101 Net Interest reserves and GLJ January 1, 2015 Forecast Prices and Costs.

(2)

Based on ARC's estimated tax pools at year-end 2014.

(3)

The after-tax net present value of ARC's oil and gas properties here reflects the tax burden on the properties on a stand-alone basis.  It does not consider the business-entity-level tax situation, or tax planning.  It does not 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 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 constitutes 81 per cent of the total proved reserves cash flow (NPV10 before tax) while total proved reserves accounts for 65 per cent of the 2P reserves cash flow (NPV10 before tax).

FUTURE DEVELOPMENT CAPITAL ("FDC")

NI 51-101 requires that F&D and FD&A costs be calculated including changes in FDC.  Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production.  Future development capital for total proved plus probable reserves increased to $3.6 billion at year-end 2014 relative to $3.3 billion at year-end 2013.  The increase in FDC in 2014 was predominantly the result of reserve additions associated with future drilling locations in the NE B.C. Montney region. Historically, capital cost reductions have lagged declines in commodity prices, consequently, ARC expects cost reductions could be recognized in 2015.

Following is a summary of GLJ estimated FDC required to bring total proved and total proved plus probable reserves on production.

Table 6


Future Development Capital (1)

$ Millions

Total

Proved

Total Proved +

Probable

2015

558

689

2016

476

679

2017

386

636

2018

285

469

2019

155

235

Remainder

218

929

Total FDC undiscounted

2,078

3,637

Total FDC discounted at 10%

1,660

2,661

(1)

FDC as per GLJ independent reserve evaluation as of December 31, 2014 and based on GLJ forecast pricing as at January 1, 2015.

FINDING, DEVELOPMENT AND ACQUISITION COSTS ("FD&A")

ARC's F&D costs were $11.51 per boe and $18.32 per boe for 2P and proved reserves, respectively in 2014, excluding FDC ($15.32 per boe and $19.58 per boe, respectively, for 2P and proved reserves, including FDC).  ARC's three year average F&D costs were $11.15 per boe for 2P reserves and $17.32 per boe for proved reserves, excluding FDC.  The low F&D costs are attributed to the high quality of ARC's property portfolio, strong results from ARC's development program and meaningful reserve growth notably at Sunrise, Septimus and Parkland/Tower.  ARC's 2014 F&D costs include approximately $62.3 million of spending in 2014 on crown lands with no significant associated reserves or production in the current year. 

Including net acquisitions, ARC's 2014 FD&A costs were $13.10 per boe of 2P reserves and $21.37 per boe of proved reserves, excluding FDC ($17.29 per boe and $22.79 per boe, respectively, for 2P and proved reserves, including FDC).  The three year average FD&A costs were $11.94 per boe for 2P reserves and $18.99 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 the highest rate of return projects. ARC's 2014 FD&A costs include approximately $62.3 million of spending on crown lands and approximately $71.7 million of spending to acquire facilities, infrastructure and lands with no significant associated reserves or production in the current year.  Additionally, ARC's FD&A costs incorporate the divestment of properties with associated reserves and production for approximately $34.2 million in 2014.

The following table illustrates Finding, Development and Acquisition ("FD&A") costs excluding and including changes in FDC.

Table 7




Excluding FDC

Including FDC

FD&A costs – Company Gross (1)(2)

$ Millions, except reserves

Proved

Proved +

Probable

Proved

Proved +

Probable

E&D capital expenditures

1,007.8

1,007.8

1,007.8

1,007.8

E&D capital expenditures - change in FDC

-

-

69.6

333.5

Total E&D capital expenditures

1,007.8

1,007.8

1,077.4

1,341.3

Net acquisition (disposition)

34.2

34.2

34.2

34.2

Net acquisition (disposition) – change in FDC

-

-

(0.4)

(0.2)

Total net acquisitions (dispositions)

34.2

34.2

33.8

34.0

Total capital including net acquisitions

1,042.0

1,042.0

1,111.2

1,375.3

E&D reserve additions, MMboe

55.0

87.5

55.0

87.5

Net acquisition (disposition) reserves, MMboe

(6.2)

(8.0)

(6.2)

(8.0)

Reserve additions including net dispositions, MMboe

48.8

79.6

48.8

79.6

(1)

The aggregate of Exploration and Development ("E&D") 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.

(2)

Under NI 51-101, the calculation of F&D costs must incorporate the change in future development capital required to bring the proved undeveloped and probable reserves to 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.

Table 7a






Excluding FDC

Including FDC

FD&A costs – Company Gross (1)(2)

$ per boe

Proved

Proved +

Probable

Proved

Proved +

Probable

F&D Costs – Current Year

18.32

11.51

19.58

15.32

F&D Costs – Prior Year

17.45

12.79

18.11

11.47

F&D Costs – Three Year Average

17.32

11.15

18.81

13.34

FD&A Costs – Current Year

21.37

13.10

22.79

17.29

FD&A Costs – Prior Year

18.31

13.32

19.18

12.07

FD&A Costs – Three Year Average

18.99

11.94

20.74

14.44

(1)

The aggregate of Exploration and Development ("E&D") costs incurred in the most recent financial year and the change during that year in estimated future development costs ("FDC") generally will not reflect total finding and development costs related to reserves additions for that year.

(2)

Under NI 51-101, the calculation of F&D costs must incorporate the change in future development capital required to bring the proved undeveloped and probable reserves to 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.

Table 8






Company Gross Historic FD&A Costs

($ per boe)

2014

2013

2012

2011

2010

Proved Reserves:






Annual FD&A excluding FDC

21.37

18.31

16.76

11.11

13.35

Three year average FD&A excluding FDC

18.99

15.00

13.38

12.02

12.82

Annual FD&A including FDC

22.79

19.18

19.96

17.13

18.21

Three year average FD&A including FDC

20.74

18.57

18.25

16.95

18.04

Proved plus Probable Reserves:






Annual FD&A excluding FDC

13.10

13.32

9.34

5.24

9.23

Three Year Average FD&A excluding FDC

11.94

8.39

7.80

7.15

8.62

Annual FD&A including FDC

17.29

12.07

13.26

12.23

14.26

Three Year Average FD&A including FDC

14.44

12.47

13.30

12.90

14.08

NE B.C. MONTNEY RESOURCES EVALUATION

The following discussion in "NE B.C. 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 "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 ECR as per the GLJ Petroleum Consultants Ltd. ("GLJ") Resources Evaluation as at December 31, 2014, prepared in accordance with the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook").  Unless indicated otherwise in this news release, all references to ECR volumes are Best Estimate ECR volumes.

The Montney formation in NE B.C. 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 crude 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 NE B.C and across the provincial border in Pouce Coupe, with a land position of 615 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 B.C. Montney region including Dawson, Parkland/Tower, Red Creek, Sunrise/Sunset, Attachie, Septimus, Sundown, and Blueberry in northeastern B.C and Pouce Coupe just across the border in Alberta (the "Evaluated Areas").  The Resources Evaluation was effective December 31, 2014 based on GLJ forecast pricing as at January 1, 2015.  All references in the following discussion to ECR, TPIIP and DPIIP are in reference to the Evaluated Areas included in the Independent Resources Evaluation.  The results of the 2014 and 2013 resources evaluations are summarized in the discussion and tables below.

The evaluation reaffirmed that the NE B.C. Montney region provides a significant long-term growth opportunity with considerable potential reserves, extending well beyond existing booked reserves and even the current estimates of the Economic Contingent Resource ("ECR").  ARC's NE B.C. 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 2014 capital development program was focused on Montney development, which was inclusive of crude oil, liquids rich-gas and dry gas opportunities.  In NE B.C., ARC's capital development program consisted of drilling 59 gross operated wells (59 net wells) comprised 11 oil wells at Tower, 22 total liquids-rich wells (18 wells at Parkland, two wells at Dawson, one at Red Creek and one at Attachie) and 26 gas wells (11 wells at Dawson and 15 wells at Sunrise). 

TPIIP for the natural gas bearing lands in the evaluated areas increased 22 per cent relative to 2013 to 67.4 Tcf. The 2014 drilling program resulted in a 16 per cent increase of DPIIP for the evaluated areas to 35.4 Tcf.  Growth in natural gas TPIIP and DPIIP is primarily attributed to 2014 land acquisition activity in Pouce Coupe, Sundown and Dawson.

Natural gas ECR increased to 4.9 Tcf from 4.5 Tcf in the 2013 evaluation and 2P natural gas reserves increased to 2.5 Tcf from 2.2 Tcf.  The increases were primarily the result of land acquisitions, drilling activity in 2014 and planned future drilling activity.  The natural gas prospective resources increased from 3.9 Tcf to 5.3 Tcf, primarily due to land acquisitions.

NGL 2P reserves associated with the natural gas resource increased nine per cent from 27.2 MMbbls in the 2013 evaluation to 29.5 MMbbls.  NGL's ECR increased 23 percent from 116.5 MMbbls to 143.2 MMbbls and NGL's prospective resource increased from 114.1 MMbbls to 157.2 MMbbls in 2014, due to increased landholdings.

On the oil bearing lands at Tower, Red Creek and Attachie East, GLJ identified 2,334 MMbbls of TPIIP and 1,807 MMbbls of DPIIP as well as 35.2 MMbbls of ECR and 14.5 MMbbls of 2P reserves.  The increase in oil TPIIP and DPIIP is attributed to land acquisition activity at Red Creek.  The increase in oil ECR is due to successful well results at Tower.  The Tower field is still in the early stages of development and Red Creek is in the exploration stage, therefore additional production data is required to better understand the recoverable potential of these fields.  However, with continual advancements in drilling and completion technology, early indications are very favorable for exploitation of this significant oil resource.

Table 9a

2014

2013

Natural Gas Resource Categories (1)(2)(3)(4)(5)

Tcf

Tcf

Total Petroleum Initially In Place (TPIIP)

67.4

55.1

Discovered Petroleum Initially In Place (DPIIP)

35.4

30.4

Undiscovered Petroleum Initially In Place (UPIIP)

32.0

24.7

(1)

TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in 2014, which means that essentially all gas bearing rock has been incorporated into the calculations.  TPIIP, DPIIP and UPIIP were estimated using a zero percent porosity cut-off in 2013, which means that essentially all gas bearing rock has been incorporated into the calculations. Using a three per cent porosity cut-off, the 2014 TPIIP, DPIIP and UPIIP "Best Estimates" would be 51.9 Tcf, 29.0 Tcf, and 22.9 Tcf, respectively.

(2)

The Resource Categories in this table do not include the free oil/liquids.

(3)

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

(4)

TPIIP includes 1.0 Tcf and DPIIP include 0.8 Tcf of solution gas associated with Tower oil and Red Creek oil.

(5)

All numbers are "Best Estimates"

Table 9b

2014

2013

Oil Resource Categories (1)(2)(3)(4)

MMbbls

MMbbls

Total Petroleum Initially In Place (TPIIP)

2,334

2,189

Discovered Petroleum Initially In Place (DPIIP)

1,807

1,714

Undiscovered Petroleum Initially in Place (UPIIP)

527

475

(1)

TPIIP, DPIIP and UPIIP have been estimated using a three percent porosity cut-off for oil due to lower mobility for oil relative to gas.  Using a six per cent porosity cut-off, the 2014 TPIIP, DPIIP and UPIIP "Best Estimates" would be 983 MMbbls, 783 MMbbls and 200 MMbbls.

(2)

All volumes in table are company gross.

(3)

The oil DPIIP is a Stock Tank Barrel ("STB")

(4)

All numbers are "Best Estimates"

Table 9c



Reserves and Economic Contingent Resources (1)(2)(5)

2014 Best

Estimate

2013 Best

Estimate

Natural Gas (Tcf)



Reserves (3)

2.5

2.2

Economic Contingent Resources

4.9

4.5

Natural Gas Liquids (MMbbls) (4)



Reserves (3)

29.5

27.2

Economic Contingent Resources

143.2

116.5

Oil (MMbbls) 



Reserves (3)

14.5

11.2

Economic Contingent Resources

35.2

10.7

(1)

All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable.  Cumulative Raw production to year end 2014 was 0.5 Tcf of gas, 1.7 MMbbls of oil and 5.7 MMbbls of NGLs, which are all immaterial in relation to the Reserves and ECR magnitude. (NGL cumulative production is calculated based on current NGL recoveries).

(2)

All volumes in table are company gross and sales volumes.

(3)

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

(4)

The liquid yields are based on average yield over the producing life of the property.

(5)

All numbers are "Best Estimates"

Table 9d



Prospective Resources (1)(2)(3)

2014 Best

Estimate

2013 Best

Estimate

Natural gas (Tcf)

5.3

3.9

Natural gas liquids (MMbbls)

157.2

114.1

(1)

All UPIIP other than Prospective Resources has been categorized as unrecoverable.  GLJ estimated DPIIP values using a porosity cut-off of three per cent for natural gas and six per cent for oil.

(2)

All volumes in table are company gross and sales volumes.

(3)

All numbers are "Best Estimates"

Based upon the forgoing analysis and ARC's expertise in the Montney formation in NE B.C., 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, completion 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 fraccing 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 discovered petroleum initially in place 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.




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 undiscovered petroleum initially in place 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 Canadian Oil and Gas Evaluation 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 percent probability (P50) 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 6 Mcf:1 BOE.  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, 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.  Our oil and gas reserves statement for the year-ended December 31, 2014, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile 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 northeastern British Columbia 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 U.S. 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 U.S. 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 U.S. 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 royalty 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 "2014 Independent Reserve Evaluation" and the recognition of significant resources under the heading "NE B.C. 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 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 plans 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 necessarily involves known and unknown risks and uncertainties, including those risks identified in this press 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 Annual Information Form).

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 $9 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 S.W., Calgary, AB T2P 0H7

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