ARC Resources Ltd. Announces Fifth Consecutive Year of Greater than 200 per cent Produced Reserves Replacement in 2012

CALGARY, Feb. 6, 2013 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") released today its 2012 year-end reserves and resources information.

HIGHLIGHTS

• Replaced 200 per cent of 2012 total production, adding 69 mmboe of proved plus probable ("2P") reserves.  2P reserves increased six per cent to 607 mmboe, comprised of 2.5 Tcf of natural gas and 186 mmbbls of crude oil and natural gas liquids ("NGL's") at year-end 2012.  ARC's 2P Reserve Life Index ("RLI") increased to 17.5 years, based on the 2013 mid-point production guidance of 95,000 boe/d.
• Replaced 214 per cent of 2012 crude oil and NGL's production, adding 29 mmbbls of 2P crude oil and NGL's reserves.  ARC's significant focus on crude oil and liquids development resulted in a nine per cent increase in 2P crude oil and NGL's reserves from 170 mmbbls to 186 mmbbls.
• Finding and Development costs ("F&D") of $9.01 per boe for 2P reserves and $15.73 per boe for proved reserves excluding Future Development Capital ("FDC"). ARC's three year average F&D costs for 2P reserves were $6.63 per boe, excluding FDC.  The 2012 capital development program focused significantly on oil and liquids development which typically carries higher finding and development costs, while yielding higher returns given the current commodity price environment.
• All-in annual Finding, Development and Acquisition ("FD&A") costs of $9.34 per boe for 2P reserves, excluding FDC. ARC's three year average FD&A costs were $7.80 per boe for 2P reserves, excluding FDC.
• Recycle ratio of 2.7 times and 3.6 times for the current year and three year average, respectively, for 2P reserves based on current and three year average F&D costs, excluding FDC, and ARC's 2012 netback of $24.17 per boe.
• ARC continued to update an Independent Resources Evaluation ("Resources Evaluation" or "Independent Resources Evaluation") for its Montney lands in the northeast British Columbia ("NE B.C.") Montney region, which reaffirmed the significant resource base on ARC's NE B.C. Montney lands.  In addition to the 50.1 Tcf of gas resource, an oil resource of 1.5 billion barrels was identified at Tower.

2012 INDEPENDENT RESERVES EVALUATION

GLJ conducted an independent reserves evaluation effective December 31, 2012 and prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and NI 51-101.  The reserve evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2013 as outlined in Table 1 below.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("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").

Based on this independent reserves evaluation, ARC's reserve profile as at December 31, 2012 is summarized below:

• ARC's year-end 2012 2P reserves increased six per cent to 607 mmboe compared to 572 mmboe of 2P reserves recorded at year-end 2011
• 2P reserve additions from exploration and development activities (including revisions) were 67.5 mmboe while 1.1 mmboe was added through acquisitions (net of minor dispositions), bringing the total additions to approximately 69 mmboe before 2012 production of 34 mmboe
• The 67.5 mmboe 2P reserves additions from development activities represents 196 per cent of the 34 mmboe produced during 2012
• Proved developed producing reserves represent 55 per cent of total proved reserves and 33 per cent of 2P reserves
• Total proved reserves account for 60 per cent of 2P reserves
• Approximately 31 per cent of ARC's proved plus probable reserves are crude oil and natural gas liquids and 69 per cent are natural gas on a 6:1 boe conversion basis
• Record positive technical revisions of 41 mmboe mainly from the Sunrise, Dawson, Ante Creek, and Pembina fields.  The positive technical revisions illustrate the strength of ARC's asset base.

Table 1
GLJ January 1, 2013 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)
2013					90.00		85.00		3.38		1.00
2014					92.50		91.50		3.83		1.00
2015					95.00		94.00		4.28		1.00
2016					97.50		96.50		4.72		1.00
2017					97.50		96.50		4.95		1.00
2018					97.50		96.50		5.22		1.00
2019					98.54		97.54		5.32		1.00
2020					100.51		99.51		5.43		1.00
2021					102.52		101.52		5.54		1.00
2022					104.57		103.57		5.64		1.00
Escalate thereafter at					+2.0%/yr		+2.0%/yr		+2.0%/yr		1.00

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 2012 (mboe)		Oil Equivalent 2011 (mboe)
Company Gross
Proved Producing	88,539		1,739		90,278			9,578		607		201,018		208,920
Proved Developed Non-producing	1,973		0		1,973			1,260		53		12,044		9,952
Proved Undeveloped	14,743		0		14,743			9,375		760		150,841		140,769
Total Proved	105,255		1,739		106,994			20,214		1,420		363,904		359,641
Proved plus Probable	146,442		2,256		148,698			36,850		2,529		606,982		572,374

Table 3
RESERVES RECONCILIATION COMPANY GROSS
		Light and Medium Crude Oil (mbbl)			Heavy Crude Oil (mbbl)			Total Crude Oil (mbbl)			NGLs (mbbl)			Natural Gas (mmcf)			Oil Equivalent (mboe)
PROVED PRODUCING
Opening Balance		87,626			1,874			89,500			10,210			655,259			208,920
	Exploration Discoveries	0			0			0			0			0			0
	Extensions and Improved Recovery(1)	9,001			167			9,168			1,250			41,202			17,285
	Technical Revisions	3,508			-44			3,464			37			53,151			12,359
	Acquisitions	140			0			140			7			118			167
	Dispositions	0			0			0			-23			-1,102			-207
	Economic Factors	-602			-13			-615			-103			-17,046			-3,559
	Production	-11,134			-245			-11,379			-1,800			-124,607			-33,947
Closing Balance		88,539			1,739			90,278			9,578			606,975			201,018
TOTAL PROVED
Opening Balance		102,188			1,874			104,062			19,088			1,418,946			359,641
	Exploration Discoveries	0			0			0			7			279			54
	Extensions and Improved Recovery (1)	11,676			167			11,843			1,989			62,485			24,246
	Technical Revisions	3,591			-44			3,547			2,305			224,366			43,246
	Acquisitions	359			0			359			-11			78			361
	Dispositions	0			0			0			-142			-3,985			-806
	Economic Factors	-1,425			-13			-1,438			-1,222			-157,388			-28,891
	Production	-11,134			-245			-11,379			-1,800			-124,607			-33,947
Closing Balance		105,255			1,739			106,994			20,214			1,420,174			363,904
PROVED PLUS PROBABLE
Opening Balance		135,071			2,308			137,379			32,774			2,413,327			572,374
	Exploration Discoveries	0			0			0			9			356			68
	Extensions and Improved Recovery(1)	19,064			278			19,342			3,086			109,529			40,683
	Technical Revisions	4,045			-76			3,969			4,174			199,221			41,347
	Acquisitions	912			0			912			204			6,676			2,229
	Dispositions	0			0			0			-203			-5,629			-1,141
	Economic Factors	-1,516			-9			-1,525			-1,394			-70,270			-14,631
	Production	-11,134			-245			-11,379			-1,800			-124,607			-33,947
Closing Balance		146,442			2,256			148,698			36,850			2,528,603			606,982

(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 increased to 17.5 years at year-end 2012 while the proved RLI was 10.5 years based upon the GLJ reserves and ARC's 2013 production guidance mid-point of 95,000 boe per day. The increase in the 2P RLI from 2008 through 2012 is attributed to the successful development of the Montney region and the resultant growth in 2P reserves.  The following table summarizes ARC's historical RLI.

Table 4
Reserve Life Index			2012(1)			2011			2010			2009			2008
Total Proved			10.5			10.7			10.4			10.3			10.3
Proved Plus Probable			17.5			17.0			15.1			14.4			13.6

(1)	Based on 2013 production guidance midpoint of 95,000 boe per day.

NET PRESENT VALUE ("NPV") SUMMARY

ARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective January 1, 2013 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.  NPVs on both a before and after tax basis are presented below.

Table 5
NPV of Cash Flow (1)	Undiscounted $MM	Discounted at 5% $MM	Discounted at 10% $MM	Discounted at 15% $MM	Discounted at 20% $MM
Before Tax
Proved Producing	5,887	4,163	3,249	2,686	2,305
Proved Developed Non-Producing	333	234	179	145	122
Proved Undeveloped	2,369	1,321	767	441	234
Total Proved	8,589	5,719	4,195	3,272	2,661
Probable	6,253	3,123	1,843	1,205	841
Proved plus Probable	14,842	8,841	6,039	4,477	3,502
After Tax (2)(3)
Proved Producing	4,985	3,582	2,829	2,360	2,039
Proved Developed Non-Producing	249	175	133	107	90
Proved Undeveloped	1,771	942	500	240	76
Total Proved	7,005	4,699	3,462	2,707	2,205
Probable	4,675	2,302	1,330	844	569
Proved plus Probable	11,680	7,001	4,792	3,552	2,774

(1)	Based on NI-51-101 Net Interest reserves and GLJ January 1, 2013 Forecast Prices and Costs.
(2)	Based on ARC's estimated tax pools at year-end 2012.
(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, the proved producing reserves constitute 54 per cent of the before tax 2P estimated value while total proved reserves account for 69 per cent of the before tax 2P estimated value.

FUTURE DEVELOPMENT CAPITAL ("FDC")

NI 51-101 requires that F&D 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.  The increase in reserves and in particular the level of undeveloped reserves booked on the Montney acreage has resulted in a higher capital cost estimate in the 2012 reserve evaluation.

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

Table 6
Future Development Capital (1) $ Millions			Total Proved			Total Proved + Probable
2013			468			601
2014			518			809
2015			492			641
2016			279			458
2017			104			352
Remainder			109			519
Total FDC undiscounted			1,970			3,380
Total FDC discounted at 10%			1,589			2,593

(1)	FDC as per GLJ independent reserve evaluation as of December 31, 2012 and based on GLJ forecast pricing as at January 1, 2013.

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

ARC's F&D costs were $9.01 per boe and $15.73 per boe for 2P and proved reserves, respectively in 2012, excluding FDC ($12.65 per boe and $18.61 per boe, respectively, for 2P and proved reserves including FDC).  ARC's three year average F&D costs were $6.63 per boe for 2P reserves and $11.49 per boe for proved reserves, excluding FDC.  The low F&D costs are attributed to the high quality of ARC's property portfolio, excellent results from ARC's development program and strong reserve growth particularly at Sunrise, Dawson, Parkland, Tower, Ante Creek, Attachie and Pembina.

Including net acquisitions, ARC's 2012 FD&A costs were $9.34 per boe of 2P and $16.76 per boe of proved reserves, excluding FDC ($13.26 per boe and $19.96 per boe, respectively, for 2P and proved reserves including FDC). The three year average FD&A costs were $7.80 per boe for 2P reserves and $13.38 per boe for proved reserves, excluding FDC.  ARC's low FD&A costs are a reflection of ARC's focus on high quality assets, cost management and allocation of resources and capital to the highest rate of return projects.

The following table illustrates FD&A costs excluding and including FDC.

Table 7
				Excluding FDC				Including FDC
FD&A costs - Company Gross (1)(2) $ Thousands				Proved	Proved + Probable			Proved	Proved + Probable
E&D capital expenditures				607,974	607,974			607,974	607,974
E&D capital expenditures - change in FDC				-	-			111,418	245,807
	Total E&D capital expenditures			607,974	607,974			719,392	853,781
Net acquisition (disposition)				32,435	32,435			32,435	32,435
Net acquisition (disposition) - change in FDC				-	-			10,781	22,717
Total net acquisition (disposition)				32,435	32,435			43,216	55,152
	Total capital including net acquisition (disposition)			640,409	640,409			762,608	908,933
E&D reserve additions				38,655	67,466			38,655	67,466
Net acquisition (disposition) reserves				(445)	1,088			(445)	1,088
	Reserve additions including net dispositions			38,210	68,554			38,210	68,554
FD&A costs - $ per boe:
F&D Costs - Current Year				15.73	9.01			18.61	12.65
F&D Costs - Three Year Average				11.49	6.63			15.99	12.02
FD&A Costs - Current Year				16.76	9.34			19.96	13.26
FD&A Costs - Three Year Average				13.38	7.80			18.25	13.30

(1)	The aggregate of Exploration and Development ("E&D") costs incurred in the most recent financial year and the change 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 FDC costs.

Table 8
Company Gross Historic FD&A Costs ($ per boe)			2012			2011			2010			2009			2008
Proved Reserves:
Annual FD&A excluding FDC			16.76			11.11			13.35			10.53			14.31
Three year average FD&A excluding FDC			13.38			12.02			12.82			13.86			18.50
Annual FD&A including FDC			19.96			17.13			18.21			14.36			22.01
Three year average FD&A including FDC			18.25			16.95			18.04			18.41			23.12
Proved plus Probable Reserves:
Annual FD&A excluding FDC			9.34			5.24			9.23			6.46			10.18
Three Year Average FD&A excluding FDC			7.80			7.15			8.62			9.61			14.85
Annual FD&A including FDC			13.26			12.23			14.26			11.59			17.08
Three Year Average FD&A including FDC			13.30			12.90			14.08			14.81			20.04

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 Resources and Operational Information" 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 Reserves, Resources and Reserves".  The discussion includes reference to TPIIP, DPIIP and ECR as per the GLJ Petroleum Consultants Ltd. ("GLJ") Resources Evaluation as at December 31, 2012, 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. 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 and 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 the region with a land position of 447 net sections, located primarily in the most prospective areas of the play.

GLJ were commissioned to conduct an Independent Resources Evaluation for ARC's lands in the NE B.C. Montney region including Dawson, Parkland, Tower, 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, 2012 based on GLJ forecast pricing as at January 1, 2013. All references in the following discussion to ECR, TPIIP and DPIIP are in reference to the Evaluated Areas included in the Independent Resources Evaluation.  See "Definitions of Oil and Gas Resources and Reserves".

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.  We believe there is considerable upside in our NE B.C. Montney assets given our significant resource base.

ARC's 2012 capital development program was focused on crude oil and liquids opportunities throughout ARC's entire asset portfolio.  In NE B.C., ARC's capital development program consisted of drilling 16 gross operated wells comprised of two dry gas wells for land retention purposes, three liquids-rich delineation wells and 11 oil wells at Tower.  Given the limited development activity in NE B.C. Montney region in 2012, the 2012 resource evaluation conducted by GLJ did not result in significant changes to resource estimates, with the exception of the Tower prospect.

Tower resource estimates were reclassified in 2012 due to the recognition of a significant portion of the Tower field as an oil reservoir in the 2012 evaluation; where previously Tower had been classified as a liquids-rich gas reservoir.  When GLJ conducted the 2011 resource evaluation, there was very limited production data at Tower, therefore, the reservoir was classified as a liquids-rich gas field.  With additional oil production data and extensive reservoir fluid and simulation analysis, GLJ now views the majority of the Tower field as an oil reservoir.

With the majority of the Tower lands now considered to be oil bearing, GLJ has split the resource assessment into two distinct sections:  Gas bearing zones which account for the vast majority of ARC's Montney lands and includes 13 upper Montney sections at Tower as well as the lower Montney at Tower; and Oil bearing zones which are restricted to the upper Montney on 43 sections of land at Tower.

TPIIP for the gas bearing lands in the evaluated areas was effectively unchanged at 50.1 Tcf, despite the reclassification of the majority of the Tower field to an oil reservoir from liquids rich gas reservoir.  The 2012 drilling program resulted in a modest increase of seven per cent DPIIP for the evaluated areas to 27.2 Tcf.

Small increases in gas ECR to 4.2 Tcf and reserves to 2.1 Tcf were primarily the result of GLJ revising upwards their view of ultimate recoverable reserves on a per well basis as a result of strong production, which more than offset reductions associated with lower forecast commodity prices.  The natural gas prospective resources decreased slightly from 4.0 Tcf to 3.8 Tcf primarily due to economic factors based on the GLJ's lower forecast commodity prices in the 2012 evaluation.

NGL reserves associated with the gas resource increased 17 per cent from 21.1 mmbbls to 24.7 mmbbls, NGL's ECR increased 10 percent from 101.0 mmbbls to 111.2 mmbbls and NGL's prospective resource increased 16 per cent to 113.6 mmbbls, due to increased land holdings, production results from the Attachie pilot, and delineation drilling at Attachie.

At Tower, ARC holds 56 net sections of which 43 sections of Upper Montney have been classified as oil bearing while the reserves and resources associated with the remaining 13 sections and the lower Montney are included in the numbers for the gas bearing lands. GLJ has identified 1,467 mmbbls of DPIIP, 12.6 mmbbls of ECR and 6.2 mmbbls of reserves on the oil bearing lands at Tower.  The Tower field is still in the early stages of development, therefore additional production data is required to better understand the recoverable potential of this field.  However, with advancements in drilling and completion technology, early indications are very favorable for exploitation of this significant oil resource.

The following tables summarize the results of the 2012 and 2011 resources evaluations.

Table 9a			2012			2011
Natural Gas Resource Categories (1)(2)(3)(4)			Tcf			Tcf
Total Petroleum Initially In Place (TPIIP)			50.1			50.4
Discovered Petroleum Initially In Place (DPIIP)			27.2			25.5
Undiscovered Petroleum Initially In Place (UPIIP)			22.9			24.9

(1)	TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cut-off which means that all gas bearing rock has been incorporated into the calculations. Using a three per cent porosity cut-off, the 2012 TPIIP, DPIIP and UPIIP estimates would be 38.5 Tcf, 22.3 Tcf, and 16.2 Tcf, respectively.
(2)	The Resource Categories do not include the free oil/liquids.
(3)	All volumes in table are company gross and raw gas volumes.
(4)	TPIIP and DPIIP include 0.7 Tcf of solution gas associated with Tower oil.

Table 9b			2012			2011
Oil Resource Categories (1)(2)(3)			mmbbls			mmbbls
Total Petroleum Initially In Place (TPIIP)			1,467.0			15.4
Discovered Petroleum Initially In Place (DPIIP)			1,467.0			15.4

(1)	TPIIP and DPIIP 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 2012 TPIIP and DPIIP estimates would both be 640.1 mmbbls.
(2)	All volumes in table are company gross.
(3)	The oil DPIIP is a Stock Tank Barrel ("STB").   The 2011 evaluation identified oil resource on only one gross section; the 2012 evaluation identified oil resource on 43 gross sections.

Table 9c
Reserves and Economic Contingent Resources (1)(2)	2012 Best Estimate	2011 Best Estimate
Natural Gas (Tcf)
Reserves (3)	2.1	1.9
Economic Contingent Resources	4.2	4.1
Natural Gas Liquids (mmbbls) (4)
Reserves (3)	24.7	21.1
Economic Contingent Resources	111.2	101.0
Oil (mmbbls)
Reserves (3)	7.6	0.1
Economic Contingent Resources	12.6	0.5

(1)	All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable.
(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.

Table 9d
Prospective Resources (1)(2)			2012 Best Estimate			2011 Best Estimate
Natural gas (Tcf)			3.8			4.0
Natural gas liquids (mmbbls)			113.6			98.0

(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.

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.  The contingencies that prevent the ECR from being classified as reserves are due to the early evaluation stage of these potential development opportunities.  Additional drilling, completion, and test results are required before these contingent resources are converted to reserves and a larger component of DPIIP is converted to ECR.

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 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, 2012, 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 and DPIIP 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 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" and "proved plus probable plus possible reserves". Probable reserves and possible 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 "2012 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 and ARC's commodity risk management programs; 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 $8 billion.  ARC expects 2013 oil and gas production to average 93,000 to 97,000 barrels of oil equivalent per day from its properties in western Canada.  ARC's Common Shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

Myron M. Stadnyk
President and Chief Executive Officer