EXHIBIT 99.1

TABLE OF CONTENTS

GLOSSARY OF TERMS	3
SPECIAL NOTES TO READER	4
REGARDING FORWARD-LOOKING STATEMENTS AND RISK FACTORS	4
ACCESS TO DOCUMENTS	5
ABBREVIATIONS AND CONVERSIONS	5
ARC RESOURCES LTD.	7
GENERAL	7
ORGANIZATIONAL STRUCTURE	7
STRATEGY	7
DEVELOPMENT OF OUR BUSINESS	8
RECENT DEVELOPMENTS	10
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	11
DISCLOSURE OF RESERVES DATA	11
FORECAST PRICES AND COSTS	13
DEFINITIONS AND NOTES TO RESERVES DATA TABLES	14
RECONCILIATIONS OF CHANGES IN RESERVES	16
FUTURE DEVELOPMENT COSTS	17
UNDEVELOPED RESERVES	18
SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA	19
FURTHER INFORMATION RESPECTING ABANDONMENTS OBLIGATIONS	20
CORE OPERATING AREAS	21
CONTINGENT RESOURCE ESTIMATES	24
OIL AND GAS WELLS	24
PROPERTIES WITH NO ATTRIBUTABLE RESERVES	25
FORWARD CONTRACTS	25
TAX HORIZON	26
CAPITAL EXPENDITURES	26
EXPLORATION AND DEVELOPMENT ACTIVITIES	27
PRODUCTION ESTIMATES	27
PRODUCTION HISTORY	28
MARKETING ARRANGEMENTS	29
CORPORATE SOCIAL RESPONSIBILITY	30
SHARE CAPITAL OF ARC RESOURCES	31
COMMON SHARES	31
PREFERRED SHARES	31
OTHER INFORMATION RELATING TO OUR BUSINESS	32
BORROWING	32
STOCK DIVIDEND PROGRAM AND DIVIDEND REINVESTMENT PLAN	33
DIRECTORS AND EXECUTIVE OFFICERS	34
MEMBERSHIP OF BOARD COMMITTEES	36
OFFICER BIOGRAPHIES	36
AUDIT COMMITTEE DISCLOSURES	39
MEMBERS OF THE AUDIT COMMITTEE	39
PRINCIPAL ACCOUNTANT FEES AND SERVICES	39
CONFLICTS OF INTEREST	41
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	42
DIVIDENDS AND DISTRIBUTIONS	42

ARC Resources Ltd. | 2016 | Annual Information Form | Page 1

DIVIDEND POLICY	42
DIVIDEND HISTORY	42
MARKET FOR SECURITIES	43
INDUSTRY CONDITIONS	44
PRICING AND MARKETING	44
THE NORTH AMERICAN FREE TRADE AGREEMENT	44
ROYALTIES AND INCENTIVES	45
LAND TENURE	46
PRODUCTION AND OPERATION REGULATIONS	46
ENVIRONMENTAL REGULATION	46
LIABILITY MANAGEMENT RATING PROGRAMS	48
CLIMATE CHANGE REGULATION	49
RISK FACTORS	52
RISKS RELATING TO OUR BUSINESS AND OPERATIONS	52
ADDITIONAL RISK FACTORS APPLICABLE TO RESIDENTS OF THE UNITED STATES AND OTHER NON-RESIDENTS OF CANADA	60
TRANSFER AGENT AND REGISTRAR	61
MATERIAL CONTRACTS	61
INTEREST OF EXPERTS	62
ADDITIONAL INFORMATION	62
APPENDIX A Form 51 101F2	63
APPENDIX B  REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION	65
APPENDIX C CONTINGENT RESOURCE ESTIMATES	66
APPENDIX D MANDATE OF THE AUDIT COMMITTEE (April 28, 2016)	72

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GLOSSARY OF TERMS

In this Annual Information Form, capitalized terms shall have the meanings set forth below:

ARC, We, Us, Our, Corporation means ARC Resources and all its controlled entities as a consolidated body at the applicable time and, prior to the completion of the Trust Conversion, the Trust and all its controlled entities as a consolidated body at the applicable time;

ARC Resources means ARC Resources Ltd., a corporation formed by amalgamation under the Business Corporations Act (Alberta);

COGE Handbook means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;

Common Shares means the common shares in the capital of ARC Resources;

GLJ means GLJ Petroleum Consultants Ltd., independent petroleum consultants of Calgary, Alberta;

GLJ Report means the report prepared by GLJ on January 16, 2017 and dated February 16, 2017 evaluating the crude oil, natural gas, natural gas liquids and sulphur reserves attributable to ARC's properties at December 31, 2016 and evaluating the crude oil, natural gas and natural gas liquids resources located in the NE BC Montney;

NE BC Montney means our lands in northeast British Columbia comprised of the Dawson, Parkland, Tower, Sunrise, Sunset, Sundown, Septimus, Attachie, Red Creek and Blueberry areas and our lands in northwestern Alberta in the Pouce Coupe area;

NI 51-101 means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities;

NI 51-102 means National Instrument 51-102 Continuous Disclosure Obligations;

Shareholders means holders of Common Shares of ARC Resources;

Tax Act means the Income Tax Act (Canada);

Trust means ARC Energy Trust, the income trust which was reorganized into ARC Resources pursuant to the Trust Conversion;

Trust Conversion means the Plan of Arrangement under Section 193 of the Business Corporations Act (Alberta) involving, among others, the Trust, ARC Resources Ltd. and the security holders of the Trust and ARC Resources Ltd. which resulted in the reorganization of the Trust into a dividend-paying, publicly-traded exploration and production corporation, being ARC Resources, which together with its subsidiaries carries on the business formerly carried on by the Trust and its subsidiaries;

Trust Units means, prior to the completion of the Trust Conversion, the units of the Trust; and

TSX means the Toronto Stock Exchange.

Certain other terms used in this Annual Information Form but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.
 

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SPECIAL NOTES TO READER

REGARDING FORWARD-LOOKING STATEMENTS AND RISK FACTORS

Certain statements contained in this Annual Information Form, and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking statements. These statements relate to future events of our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek,” “anticipate,” “budget,” “plan,” “continue,” “estimate,” “expect,” “forecast,” “may,” “will,” “project,” “predict,” “potential,” “target,” “intend,” “could,” “might,” “should,” “believe,” and similar expressions. In addition, there are forward-looking statements in this Annual Information Form under the headings: “Statement of Reserves Data and Other Oil and Gas Information” as to our reserves and future net revenues from our reserves, pricing and inflation rates and future development costs; as to the development of our proved undeveloped reserves and probable undeveloped reserves; as to our future development activities, the status of our enhanced recovery projects, hedging policies, reclamation and abandonment obligation, tax horizon, exploration and development activities and production estimates; and in Appendix C entitled “Contingent Resource Estimates” as to our contingent resource estimates on our NE BC Montney properties. These 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 statements. We believe the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this Annual Information Form should not be unduly relied upon. These statements speak only to estimates as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference into this Annual Information Form, as the case may be.

In addition to the forward-looking statements identified above, this Annual Information Form, and the documents incorporated by reference, contain forward-looking statements pertaining to the performance characteristics of our crude oil and natural gas properties; crude oil and natural gas production levels; the size of the crude oil and natural gas reserves and of our contingent resources, projections of market prices and costs; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; treatment under governmental regulatory regimes and tax laws; and capital expenditure programs.

Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. In addition, these risks and uncertainties are material factors affecting the success of our business. Such factors include, but are not limited to: declines in crude oil and natural gas prices; various pipeline constraints; the payment of dividends, if any; variations in interest rates and foreign exchange rates; stock market volatility; uncertainties relating to market valuations; refinancing risk for existing debt and debt service costs; access to external sources of capital; risks associated with our hedging activities; third-party credit risk; risks associated with the exploitation of our properties and our ability to acquire reserves; government regulation, policy and control and changes in governmental legislation; changes in income tax laws, royalty rates and other incentive programs; uncertainties associated with estimating crude oil and natural gas reserves and resources; risks associated with acquiring, developing and exploring for crude oil and natural gas and other aspects of our operations; our reliance on hydraulic fracturing; certain of our enhanced recovery projects are not currently economically feasible;risks associated with large projects or expansion of our activities; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in climate change laws and other environmental regulations; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; risks of non-cash losses as a result of the application of accounting policies;our operating activities and ability to retain key personnel; depletion of our reserves; risks associated with securing and maintaining title to our properties; risks for United States and other non-resident Shareholders; risks described in further detail under “Risk Factors” herein; and other factors, many of which are beyond our control.

The actual results could differ materially from those results anticipated in these forward-looking statements, which are based on assumptions, including as to the market prices for crude oil and natural gas; the continuation of the present policies of the Board of Directors relating to management of ARC, and the payment of dividends, capital expenditures and other matters; the continued availability of capital, acquisitions of reserves, undeveloped lands and skilled personnel; the continuation of the current tax and regulatory regime and other assumptions contained in this Annual Information Form.

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Statements relating to “reserves” and “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described can be profitably produced in the future.

Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking statements except as required by securities laws or regulations.

ACCESS TO DOCUMENTS

Any document referred to in this Annual Information Form and described as being filed on our SEDAR profile at www.sedar.com (including those documents referred to as being incorporated by reference in this Annual Information Form) may be obtained free of charge from us at 1200, 308 – 4^th Avenue SW, Calgary, Alberta, T2P 0H7.

ABBREVIATIONS AND CONVERSIONS

Oil and NGLs
bbl	barrel
Mbbl	thousand barrels
MMbbl	million barrels
bbl/d	barrels per day
NGLs	natural gas liquids
Natural Gas
Mcf	thousand cubic feet
Mcf/d	thousand cubic feet per day
MMcf	million cubic feet
MMcf/d	million cubic feet per day
Bcf	billion cubic feet
Bcfe	billion cubic feet equivalent
Tcf	trillion cubic feet
MMBtu	million British thermal units
Other
API	Indication of specific gravity of crude oil measured on the API gravity scale
boe	barrels of oil equivalent
boe/d	barrels of oil equivalent per day
GJ	gigajoules
Mboe	thousand barrels of oil equivalent
$MM	million dollars

We have adopted the standard of 6 Mcf:1 barrel when converting natural gas to boe. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.

All dollar amounts set forth in this Annual Information Form are in Canadian dollars, except where otherwise indicated.

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The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By
cubic metres	cubic feet	35.315
barrels	cubic metres	0.159
cubic metres	barrels	6.290
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.4047
hectares	acres	2.471

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ARC RESOURCES LTD.

GENERAL

ARC Resources was formed by amalgamation under the Business Corporations Act (Alberta). Prior to January 1, 2011, ARC was one of Canada's largest conventional oil and gas royalty trusts and was founded in 1996.

Currently, ARC is one of Canada’s leading conventional oil and gas corporations with average production in 2016 of 118,671 boe per day. ARC’s business activities include the exploration, development and production of crude oil, natural gas and natural gas liquids in four core areas located in Alberta and British Columbia, Canada. ARC has focused on the acquisition and development of resource-rich properties that provide an option for both near-term and long-term growth. ARC trades on the TSX under the symbol ARX and currently pays a monthly dividend to its Shareholders.

At December 31, 2016, ARC had approximately 464 professional, technical and support staff, with 261 employees in the Calgary office and 203 employees located across ARC’s operating areas.

Our principal office is located at 1200, 308 – 4^th Avenue SW, Calgary, Alberta, T2P 0H7 and our registered office is located at 2400, 525 – 8^th Avenue SW, Calgary, Alberta, T2P 1G1.

ORGANIZATIONAL STRUCTURE

ARC Resources is a sole legal entity and does not have any subsidiaries or affiliates as of December 31, 2016.

Effective March 1, 2016, 1504793 Alberta Ltd. was wound up resulting in the dissolution of ARC Resources General Partnership.

STRATEGY

ARC’s vision is to be a leading energy producer, focused on delivering results through its strategy of risk-managed value creation. ARC is committed to providing superior long-term financial returns for its Shareholders, creating a culture where respect for the individual is paramount and action and passion are rewarded. ARC runs its business in a manner that protects the safety of employees, communities and the environment. ARC’s vision is realized through the four pillars of its strategy:

High-quality, long-life assets – ARC’s unique suite of assets includes primarily Montney and Cardium assets. ARC’s Montney assets consist of world-class resource play properties, concentrated in northeast British Columbia and northern Alberta. The Montney assets provide substantial growth opportunities, which ARC will pursue to create value through long-term profitable development. Other assets are located in Alberta and include core assets in the Cardium formation in the Pembina area of Alberta. These assets deliver stable production and contribute cash to fund future development and support ARC's dividend.

Operational excellence – ARC is focused on capital discipline and cost management to extract the maximum return on its investments while operating in a safe and environmentally responsible manner. Production from individual crude oil and natural gas wells naturally declines over time. In any one year, ARC approves a budget to drill new wells with the intent to first replace production declines and second to potentially increase production volumes, when both can be done profitably. At times, ARC may also acquire strategic producing or undeveloped properties to enhance current production and reserves or to provide potential future drilling locations. Alternatively, it may strategically dispose of non-core assets that no longer meet its investment criteria.

Financial flexibility – ARC provides returns to Shareholders through a combination of a monthly dividend, currently $0.05 per share per month, and the potential for capital appreciation. ARC’s long-term goal is to fund dividend payments and capital expenditures necessary for the replacement of production declines using funds from operations ⁽¹⁾. ARC will finance value-creating growth activities through a combination of sources including funds from operations, proceeds from property dispositions, debt capacity, and when appropriate, equity issuance. ARC chooses to maintain prudent debt levels. At year-end 2016, ARC’s net debt to annualized funds from operations was 0.5 times,

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however over the long term ARC targets a net debt to annualized funds from operations between one and 1.5 times and less than 20 per cent of total capitalization⁽¹⁾.

Top talent and strong leadership culture – ARC is committed to the attraction, retention and development of the best and brightest people in the industry. ARC’s employees conduct business every day in a culture of trust, respect, integrity and accountability. Building leadership talent at all levels of the organization is a key focus. ARC is also committed to corporate leadership through community investment, environmental reporting practices and open communication with all stakeholders.

(1) Net debt and total capitalization are non-generally accepted accounting principles ("GAAP") measures which may not be comparable to similar additional GAAP measures used by other entities. For more information, see the section entitled "Non-GAAP Measures" contained within our Management's Discussion and Analysis for the year ended December 31, 2016, which note is incorporated in this Annual Information Form by reference and is found on our SEDAR profile at www.sedar.com. Also refer to the "Funds from Operations" section within the Management's Discussion and Analysis for a reconciliation of ARC's net income to funds from operations and cash flow from operating activities, which note is also incorporated into this Annual Information Form and can also be found on our SEDAR profile at www.sedar.com.

DEVELOPMENT OF OUR BUSINESS

The following is a description of the general development of our business over the last three financial years. During this period, ARC operated in one of the most challenging commodity price and capital market environments in the history of our Company.

2014

Average annual production of 112,387 boe per day. ARC achieved full-year production of 112,387 boe per day, which was 17 per cent higher than 2013. New wells at Parkland/Tower and Sunrise, as well as continued strong production at Ante Creek were the primary drivers of higher full-year 2014 production. ARC's 2014 annual average production was within the original guidance range of 110,000 to 114,000 boe per day. This was achieved despite the divestment of 2,400 boe per day of production in the second quarter of 2014.

Proved plus probable reserves of 673 MMboe identified and 210 per cent of produced reserves replaced. GLJ determined ARC’s proved plus probable reserves increased six per cent relative to 2013, to total 673 MMboe, and that approximately 210 per cent of produced reserves were replaced through capital development activity.

Sunrise Phase I construction initiated. Construction began on the new 60 MMcf per day Sunrise gas processing facility in the fourth quarter of 2014.

Capital expenditures totaled $945.5 million. During 2014, ARC invested $945.5 million in capital activities, before land purchases and net acquisitions and dispositions. The 2014 capital program focused primarily on crude oil and liquids-rich natural gas opportunities at Parkland/Tower, Ante Creek, Pembina, and southeast Saskatchewan along with investment in natural gas development at Dawson and Sunrise. ARC drilled 187 gross operated wells (139 crude oil wells, 22 liquids-rich natural gas wells and 26 natural gas wells) in 2014.

ARC completed $135.8 million of land purchases and “tuck-in” land and infrastructure acquisitions in key development areas. In the Montney region, ARC grew its land position by approximately 120 net sections in 2014. ARC was the third largest Montney land holder with approximately 990 net Montney sections, including 529 net sections in northeast British Columbia and an additional 461 net Montney sections in northern Alberta.

Extension of credit facility. ARC had a $1 billion financial covenant-based syndicated credit facility with 12 banks at December 31, 2014. This facility was extended in 2014 for one additional year until November 6, 2018. At December 31, 2014, ARC had available credit of $916.4 million taking into account ARC's year-end working capital deficit on total credit facilities of $2.2 billion. The net debt to 2014 funds from operations ratio was 1.1 times and net debt was approximately 14 per cent of ARC's total capitalization; both metrics were well within ARC's target levels.

2015

Average annual production of 114,167 boe per day. ARC achieved full-year production of 114,167 boe per day in 2015. Notably, annual average production was two percent higher than 2014, despite a significantly reduced capital program and the divestment of approximately 4,900 boe per day of production volumes throughout the year, which resulted in an annual volume impact of approximately 3,000 boe per day. New wells brought on in the latter part of the year at Sunrise and Tower to coincide with the completion of new facilities in these areas were the main drivers of increased production volumes.

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Proved plus probable reserves of 687 MMboe identified and 190 per cent of produced reserves replaced. GLJ determined ARC’s proved plus probable reserves increased two per cent relative to 2014, to total 687 MMboe, and that approximately 190 per cent of produced reserves were replaced through capital development activity.

Capital expenditures totaled $541.6 million. During 2015, ARC invested $541.6 million in capital activities, before land purchases and net acquisitions and dispositions, which included the drilling of 60 gross operated wells (33 crude oil wells, 21 natural gas wells, five liquids-rich wells, and one service well). The majority of capital activity in the year was focused on ARC’s profitable NE BC Montney region.

Commissioning of key infrastructure. Key infrastructure projects were completed during the year, including the commissioning of the Sunrise gas plant in the third quarter of 2015 and the Tower battery expansion in the fourth quarter of 2015.

ARC completed $21.1 million of land purchases and “tuck-in” land acquisitions in key development areas. In the Montney region, ARC grew its land position by approximately 210 net sections, increasing its total position to approximately 1,174 net Montney sections, including 641 net sections in northeast British Columbia and an additional 533 net sections in northern Alberta. During 2015, ARC divested of certain non-core assets for gross proceeds of $88.8 million, which included the divestment of its properties in Manitoba in the fourth quarter of 2015.

Equity issuance completed. In January 2015, ARC issued 17.9 million Common Shares at a price of $22.55 per share for aggregate proceeds of $402.7 million on a bought deal basis. Share issue costs of $16.6 million were incurred as a result of this transaction. The proceeds from the equity issuance were directed to reduce bank indebtedness, increase working capital and fund ARC’s ongoing capital programs.

Extension of credit facility. ARC had a $1 billion financial covenant-based syndicated credit facility with 12 banks. This facility was extended in 2015 for one additional year until November 6, 2019. At December 31, 2015, ARC had available cash and credit of approximately $1.4 billion, taking into account ARC’s long-term debt and working capital surplus balance of $985.1 million. Net debt to 2015 funds from operations ratio was 1.3 times and net debt was approximately 15 per cent of ARC's total capitalization. Both of the foregoing metrics were within ARC's target levels.

2016

Average annual production of 118,671 boe per day. ARC achieved record full-year production of 118,671 boe per day in 2016, representing a four per cent increase relative to full-year 2015 production. The modest growth in production was achieved despite a reduced capital program and the divestment of approximately 8,800 boe per day of non-core production throughout the year. The increase in year-over-year production was the result of numerous strategic activities including the commissioning of the expanded oil battery in Parkland/Tower in late 2015, the commissioning of the Sunrise gas processing facility in mid-2015, and the acquisition of assets in Pembina in 2016.

Proved plus probable reserves of 737 MMboe identified and 260 per cent of produced reserves replaced. GLJ determined ARC’s proved plus probable reserves increased seven per cent relative to 2015, to total 737 MMboe, and that approximately 260 per cent of produced reserves were replaced through capital development activity.

Capital expenditures totaled $453.4 million.  During 2016, ARC invested $453.4 million in capital expenditures, before land and net acquisitions and dispositions. Despite a reduced capital budget, ARC executed a successful capital program in 2016 advancing long term strategic projects and delivering annual average production that was within guidance. The majority of the capital program was focused on the NE British Columbia region and included the drilling of 64 gross operated wells (34 crude oil wells, 20 liquids-rich, nine natural gas, and one service well), strategic infrastructure spending on the Dawson Phase III processing facility, and the continued advancement of ARC’s large asset base across the Montney play.

Right-sizing of the dividend. In February 2016, ARC’s Board of Directors approved a monthly dividend of $0.05 per share, down from the previous level of $0.10 per share, commencing with the February 2016 dividend, payable on March 15, 2016. The lower monthly dividend reduced ARC’s funding requirements in the year by approximately $200 million, preserving balance sheet strength and better aligning dividends declared to funds from operations.

Realized hedging gains of $216.5 million. ARC had realized hedging gains of $216.5 million on its risk management contracts in 2016, which represented 34 per cent of annual funds from operations.

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Strengthened our base business. In a continued effort to advance our strategy of a concentrated asset base of world-class assets, ARC completed strategic acquisition and divestment activities in 2016. Throughout the year, we successfully added to our working interest ownership in the Pembina Cardium acquiring approximately 3,100 boe per day of light, high netback crude oil production. In December 2016, ARC sold all of its Saskatchewan assets and operations. The sale included approximately 7,500 boe per day of production and 37,893 Mboe of proved plus probable reserves.

Construction progressed at Dawson Phase III. During the year,ARC progressed construction of the Dawson Phase III gas processing and liquids handling facility.  The first stage of Dawson Phase III is designed to process 90 MMcf per day and handle 7,500 barrels per day of liquids (approximately 50 per cent condensate-handling), and is expected to be on-stream in late 2017.

RECENT DEVELOPMENTS

Increased 2017 capital budget to $750 million. ARC’s Board of Directors announced an increase to the 2017 capital budget from $665 million (previously announced) to $750 million. The $750 million 2017 capital budget will focus on long-term value creation, balance sheet strength, sustainable dividend payments, and the continued development of ARC's low-cost Montney crude oil, liquids-rich gas, and natural gas assets. ARC's 2017 budget sustains production, funds the completion of the Dawson Phase III gas processing and liquids-handling facility, and allows for initial investment in strategic infrastructure spending at Parkland/Tower and Sunrise. Infrastructure spending at  Parkland/Tower will progress the Phase III gas processing and liquids-handling facility expansion, which will add an additional 60 MMcf per day of natural gas and 7,500 barrels per day of crude oil sales, and is expected to come on-stream in late 2018.  At Sunrise, front-end engineering and design work will be initiated for the Phase II gas processing facility expansion which will having a design capacity of 120 MMcf per day of natural gas sales, of which 60 MMcf per day will come from production currently flowing through a third-party facility and 60 MMcf per day will be incremental production. Sunrise Phase II is the newest sanctioned project for Montney growth, and is expected to come on-stream mid-year in 2019

Elimination of the DRIP/SDP. On February 8, 2017, ARC’s Board of Directors announced the elimination of the Dividend Reinvestment Plan (“DRIP”) and Stock Dividend Plan (“SDP”). Elimination of both programs will apply to the April 17, 2017 dividend payment to Shareholders of record on March 31, 2017. The ex-dividend date is March 29, 2017. For more information please see the February 8, 2017 news release titled “ARC Resources Ltd. Announces Fourth Quarter and Year-End 2016 Results as It Increases Capital Investment in ARC's Multi-Year, Large-Scale Development Projects at Dawson, Parkland/Tower, and Sunrise”.

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STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas information is set forth below (the “Statement”). The effective date of the Statement is December 31, 2016. The reserves data conforms to the requirements of NI 51-101.

The reserves data set forth below is based upon an evaluation by GLJ and contained in the GLJ Report dated February 16, 2017. The reserves data summarizes our crude oil, liquids and natural gas reserves and the net present values of future net revenues for these reserves, using forecast prices and costs prior to provision for interest, general and administrative expenses, the impact of any hedging activities or the liability associated with the abandonment and reclamation of certain wells, pipelines and facilities. Future net revenues have been presented on a before- and after-tax basis. We engaged GLJ to provide an evaluation of proved and proved plus probable reserves.

All of ARC’s 2016 reserves were in Canada. At the start of 2016, ARC had reserves in the provinces of Alberta, British Columbia and Saskatchewan. In the fourth quarter of 2016, ARC divested all of its Saskatchewan assets, and therefore no reserves were booked in Saskatchewan as at December 31, 2016.  At December 31, 2016 certain assets located in Alberta were classified as assets held for sale and as such were reclassified out of property, plant and equipment (“PP&E”) and asset retirement obligations (“ARO”) on the balance sheet.  These assets have booked reserves and were included in the 2016 reserve values and in net present value calculations.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in “Definitions and Notes to Reserves Data Tables” in conjunction with the following tables and notes. For more information as to the risks involved, see “Risk Factors – Risk Relating to Our Business and Operations”.

The Report on Reserves Data by GLJ on Form 51-102F2 and the Report of Management and Directors on Reserves Data and Other Information on Form 51-101F3 are attached as Appendices A and B to this Annual Information Form.

As per NI 51-101 product type definitions, ARC has provided reserves data for reserves classified as Shale Gas. ARC’s gas reserves and resources in the NE BC Montney siltstone are classified as shale gas under NI 51-101.

DISCLOSURE OF RESERVES DATA

Company Gross reserves information presented herein is consistent with reserves information disclosed in the February 8, 2017news release entitled, “ARC Resources Ltd. Replaces 260 Per Cent of Produced Reserves Through Development Activities in 2016”.

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Summary of 2016 Oil and Gas Reserves – Based on Forecast Prices and Costs

Company Gross Reserves	Light Crude Oil and Medium Crude Oil (Mbbl)		Heavy Crude Oil (Mbbl)		Tight Oil (Mbbl)		Total Oil (Mbbl)		Conventional Natural Gas (Bcf)		Shale Gas (Bcf)		Total Gas (Bcf)		NGLs (Mbbl) (1)		Total Oil Equivalent (Mboe)
PROVED
Developed  Producing		51,611		1,648		13,697		66,956		69.0		725.1		794.1		13,040		212,341
Developed  Non-Producing		728		-		853		1,581		2.3		48.3		50.6		916		10,930
Undeveloped		6.088		80		14,078		20,247		8.1		941.8		949.8		24,108		202,656
TOTAL  PROVED		58,427		1,728		28,628		88,783		79.4		1,715.1		1,794.5		38,064		425,927
Probable		19,024		556		15,633		35,213		27.5		1,425.4		1,452.9		33,440		310,806
TOTAL  PROVED +  PROBABLE		77,451		2,284		44,261		123,996		106.9		3,140.5		3,247.4		71,504		736,733
Company Net Reserves	Light Crude Oil and Medium Crude Oil (Mbbl)		Heavy Crude Oil (Mbbl)		Tight Oil (Mbbl)		Total Oil (Mbbl)		Conventional Natural Gas (Bcf)		Shale Gas (Bcf)		Total Gas (Bcf)		NGLs (Mbbl) (1)		Total Oil Equivalent (Mboe)
PROVED
Developed  Producing		47,420		1,770		12,263		61,453		64.0		608.6		672.6		10,247		183,800
Developed  Non-Producing		644		0		750		1,394		2.0		42.6		44.6		761		9,591
Undeveloped		5,682		76		12,238		17,995		7.7		791.8		799.5		20,625		171,865
TOTAL  PROVED		53,746		1,845		25,251		80,843		73.7		1,443.0		1,516.7		31,634		365,256
Probable		16,462		565		13,409		30,435		25.6		1,163.2		1,188.8		27,723		256,292
TOTAL  PROVED +  PROBABLE		70,208		2,410		38,660		111,278		99.3		2,606.2		2,705.5		59,356		621,548

1) Natural Gas Liquids includes Associated Natural Gas Liquids for both Conventional and Shale/Tight Reservoirs, and includes condensate, propane and butane.

Net Present Value of Future Net Revenues – Based on Forecast Prices and Costs

Before-Tax (1) ($ millions)	Undiscounted		Discounted at 5%		Discounted at 10%		Discounted at 15%		Discounted at 20%
PROVED
Developed Producing		4,626		3,296		2,585		2,148		1,852
Developed Non-Producing		154		116		91		75		63
Undeveloped		2,729		1,593		982		615		380
TOTAL PROVED		7,509		5,005		3,659		2,839		2,295
Probable		6,531		3,451		2,174		1,519		1,134
TOTAL PROVED + PROBABLE		14,040		8,457		5,832		4,358		3,429
After-Tax (1)(2)(3) ($ millions)
PROVED
Developed Producing		3,827		2,786		2,218		1,863		1,619
Developed Non-Producing		112		84		66		54		45
Undeveloped		2,002		1,123		647		362		179
TOTAL PROVED		5,941		3,993		2,931		2,278		1,843
Probable		4,778		2,511		1,565		1,079		795
TOTAL PROVED + PROBABLE		10,719		6,504		4,496		3,358		2,638

1) Future net revenue values are net of estimated abandonment and reclamation for all wells (both existing and undrilled wells) that have been attributed reserves, including those associated with properties moved to held for sale at December 31, 2016.  Additional information related to our estimated share of future environmental and reclamation obligations for the working interest properties (including all abandonment and reclamation costs associated with all existing wells, pipeline, facilities and surface lease reclamations) can be found in ARC's audited financial statements for the year ended December 31, 2016 and the accompanying management's discussion and analysis, which are available on SEDAR at www.sedar.com.

2) Based on ARC’s estimated tax pools at year-end 2016.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 12

3) The after-tax net present value of ARC's oil and gas properties presented here reflect the income 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 net present value at the level of the business entity, which may be significantly different. ARC's audited consolidated financial statements for the year ended December 31, 2016 and the related Management's Discussion and Analysis should be consulted for information at the business entity level.

Total Future Net Revenues (Undiscounted) – Based on Forecast Prices and Costs

Reserves Category ($ millions)	Revenue		Royalties		Operating Costs		Development Costs		Abandonment and Reclamation Costs (1)		Future Net Revenue before Income Taxes		Income Taxes		Future Net Revenue after Income Taxes
Proved  Reserves		17,486		2,012		5,690		1,908		366		7,509		1,568		5,941
Proved Plus  Probable  Reserves		30,448		3,885		9,305		2,755		462		14,040		3,322		10,719

1) Reflects estimated abandonment and reclamation for all wells (both existing and undrilled wells) that have been attributed reserves, including those associated with properties moved to held for sale at December 31, 2016. This does not account for pipelines, facilities or surface lease reclamations, or for abandonment and reclamation costs for wells with no attributed reserves.

Future Net Revenues by Production Group – Based on Forecast Prices and Costs

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (Discounted at 10% per Year) ($ millions)	Per Unit (1)
Proved Reserves	Light Crude Oil and Medium Crude Oil (2)	983	$15.33/boe
	Heavy Crude Oil (2)(3)	35	$18.24/boe
	Tight Oil (2)	691	$14.81/boe
	Conventional Natural Gas (4)	26	$0.90/Mcfe
	Shale Gas (4)	1,924	$1.29/Mcfe
	Total	3,659	$10.02/boe
Proved + Probable Reserves	Light Crude Oil and Medium Crude Oil (2)	1,238	$14.64/boe
	Heavy Crude Oil (2)(3)	43	$17.39/boe
	Tight Oil 2)	1,185	$15.03/boe
	Conventional Natural Gas (4)	33	$0.88/Mcfe
	Shale Gas (4)	3,334	$1.24/Mcfe
	Total	5,832	$9.38/boe

1) Unit values are based on Net Reserves.

2) Including solution gas and other by-products.

3) Per unit revenue positively impacted by a portion of value coming from royalty interest reserves.

4) Including by-products but excluding solution gas and other by-products from oil wells.

FORECAST PRICES AND COSTS

These are prices and costs that are generally acceptable, in the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation effective date. To the extent that there are fixed or presently determinable future prices or costs to which we are legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs shall be incorporated into the forecast prices.

The forecast cost and price assumptions include increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil, natural gas and natural gas liquids benchmark reference pricing as at December 31, 2016, and inflation and exchange rates utilized in the GLJ Report were as follows:

ARC Resources Ltd. | 2016 | Annual Information Form | Page 13

Summary of Forecast Prices and Inflation Rate Assumptions

	Oil								Natural Gas		Edmonton Liquids Prices
	WTI Cushing Oklahoma (US$/bbl)		Edmonton Par Price 40° API (Cdn$/bbl)		Hardisty Heavy12° API (Cdn$/bbl)		Cromer Medium 29.3° API (Cdn$/bbl)		AECO Gas Price (Cdn$/ MMBtu)		Propane (Cdn$/bbl)		Butane (Cdn$/bbl)		Pentanes Plus (Cdn$/bbl)		Inflation Rate (1) (%/Year)		Exchange Rate (2) (US$/Cdn$)
Forecast
2017		55.00		69.33		46.69		64.48		3.46		28.43		49.92		72.11		2.0		0.750
2018		59.00		72.26		50.40		67.20		3.10		26.74		54.19		74.79		2.0		0.775
2019		64.00		75.00		55.03		69.75		3.27		26.25		56.25		78.75		2.0		0.800
2020		67.00		76.36		56.96		71.02		3.49		26.73		57.27		79.80		2.0		0.825
2021		71.00		78.82		59.95		73.31		3.67		27.59		59.12		82.37		2.0		0.850
2022		74.00		82.35		63.43		76.59		3.86		28.82		61.76		86.06		2.0		0.850
2023		77.00		85.88		66.99		79.87		4.05		30.06		64.41		89.32		2.0		0.850
2024		80.00		89.41		70.48		83.15		4.16		31.29		67.06		92.99		2.0		0.850
2025		83.00		92.94		73.63		86.44		4.24		32.53		69.71		97.59		2.0		0.850
2026		86.05		95.61		77.54		88.92		4.32		33.46		71.71		99.91		2.0		0.850
Thereafter		(3)		(3)		(3)		(3)		(3)		(3)		(3)		(3)		2.0		0.850

1) Inflation rates for forecasting costs.

2) Exchange rates used to generate the benchmark reference prices in this table.

3) Prices escalate twoper cent per year from 2026.

ARC’s weighted average prices realized, prior to hedging, for the year ended December 31, 2016, were Cdn$2.23 per Mcf for shale gas and conventional natural gas, Cdn$50.69 per barrel for tight oil, light crude oil and medium crude oil, Cdn$32.62 per barrel for heavy crude oil and Cdn$50.98 per barrel for condensate and Cdn$13.85 per barrel for natural gas liquids. Only a minor amount of our production is characterized as heavy crude oil.

DEFINITIONS AND NOTES TO RESERVES DATA TABLES

In the tables set forth above and elsewhere in this Annual Information Form, the following definitions and other notes are applicable:

1. “Gross” means:

a) in relation to our interest in production and reserves, our interest (operating and non-operating) before deduction of royalties and without including any royalty interest to us;

b) in relation to wells, the total number of wells in which we have an interest; and

c) in relation to properties, the total area of properties in which we have an interest.

2. “Net” means:

a) in relation to our interest in production and reserves, our interest (operating and non-operating) after deduction of royalty obligations, plus our royalty interest in production or reserves;

b) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

c) in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest we owned.

3. Columns may not add due to rounding.

4. The forecast price and cost assumptions assumed the continuance of current laws and regulations.

5. All factual data supplied to GLJ was accepted as represented. No field inspection was conducted.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 14

6. The crude oil, natural gas liquids and natural gas reserves estimates presented in the GLJ Report are based on the definitions and guidelines contained in the CSA Notice 51-324 – Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities and the COGE Handbook. A summary of those definitions are set forth below.

Reserves Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on analysis of drilling, geological, geophysical and engineering data; through the use of established technology; and within specified economic conditions.

Reserves are classified according to the degree of certainty associated with the estimates.

a) 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.

b) 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.

Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:

a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

a) at least a 90 per cent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

ARC Resources Ltd. | 2016 | Annual Information Form | Page 15

b) at least a 50 per cent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

RECONCILIATIONS OF CHANGES IN RESERVES

The following table sets forth the reconciliation of our gross reserves as at December 31, 2016, using forecast price and cost estimates derived from the GLJ Report. Gross reserves as at December 31, 2016 and as at December 31, 2015 include working interest reserves before royalties payable and without including gross royalties receivable.

In the Proved and Proved plus Probable reconciliations, overall material increases in Extensions, Improved Recovery and Technical revisions were driven by growth on core Montney properties. Assets acquired in the Pembina area materially contributed to Acquisitions, while assets divested in Saskatchewan materially contributed to Dispositions.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 16

Reconciliation of Gross Reserves by Principal Product Type

	Light Crude Oil and Medium Crude Oil (Mbbl)			Heavy Crude Oil (Mbbl)			Tight Oil (Mbbl)			Total Oil (Mbbl)			Conven-tional Natural Gas (Bcf)			Shale Gas (Bcf)			Coal Bed Methane (Bcf)			Total Gas (Bcf)			NGLs(Mbbl) (1)			Total Oil Equivalent 2016 (Mboe)
PROVED
December 31, 2015		73,755			1,336			23,769			98,860			73.3			1,512.9			6.3			1,592.5			29,052			393,327
Discoveries		-			-			-			-			-			-			-			-			-			-
Extensions and   Improved Recovery (2)		3,141			-			8,695			11,836			2.7			193.7			-			196.4			4,819			49,391
Technical Revisions		1,203			567			1,024			2,794			8.1			184.3			-			192.4			7,176			42,030
Acquisitions		12,468			-			-			12,468			13.9			-			-			13.9			573			15,352
Dispositions		(25,044	)		-			-			(25,044	)		(10.0	)		-			(5.9	)		(15.9	)		(469	)		(28,161	)
Economic Factors		(586	)		(37	)		(117	)		(740	)		(0.3	)		(11.2	)		-			(11.5	)		(208	)		(2,865	)
Production		(6,511	)		(138	)		(4,743	)		(11,392	)		(8.1	)		(164.6	)		(0.5	)		(173.3	)		(2,879	)		(43,148	)
December 31, 2016		58,427			1,728			28,628			88,783			79.4			1,715.1			-			1,794.5			38,064			425,927
PROBABLE
December 31, 2015		29,661			428			17,535			47,623			28.7			1,297.8			3.1			1,329.7			24,292			293,524
Discoveries		-			-			-			-			-			-			-			-			-			-
Extensions and   Improved Recovery (2)		(3,041	)		-			1,400			(1,642	)		(2.6	)		183.0			-			180.3			6,642			35,053
Technical Revisions		(574	)		144			(3,262	)		(3,694	)		1.4			(51.0	)		-			(49.7	)		2,475			(9,496	)
Acquisitions		3,536			-			-			3,536			4.0			-			-			4.0			166			4,375
Dispositions		(10,769	)		-			-			(10,769	)		(3.7	)		-			(3.1	)		(6.8	)		(183	)		(12,085	)
Economic Factors		211			(16	)		(39	)		156			(0.3	)		(4.3	)		-			(4.6	)		48			(566	)
Production		-			-			-			-			-			-			-			-			-			-
December 31, 2016		19,024			556			15,633			35,212			27.5			1,425.4			-			1,452.9			33,441			310,806
PROVED PLUS PROBABLE
December 31, 2015		103,416			1,764			41,303			146,483			102.0			2,810.7			9.4			2,922.1			53,343			686,851
Discoveries		-			-			-			-			-			-			-			-			-			-
Extensions and   Improved Recovery (2)		100			-			10,095			10,195			0.1			376.7			-			376.7			11,462			84,445
Technical Revisions		630			711			(2,238	)		(897	)		9.4			133.2			-			142.7			9,652			32,535
Acquisitions		16,004			-			-			16,004			17.9			-			-			17.9			740			19,727
Dispositions		(35,812	)		-			-			(35,812	)		(13.7	)		-			(9.0	)		(22.7	)		(652	)		(40,246	)
Economic Factors		(375	)		(53	)		(156	)		(584	)		(0.6	)		(15.5	)		-			(16.1	)		(160	)		(3,431	)
Production		(6,511	)		(138	)		(4,743	)		(11,392	)		(8.1	)		(164.6	)		(0.5	)		(173.3	)		(2,879	)		(43,148	)
December 31, 2016		77,451			2,284			44,261			123,996			106.9			3,140.5			-			3,247.4			71,504			736,733

1) Natural Gas Liquids includes Associated Natural Gas Liquids for both Conventional and Shale/Tight Reservoirs.

2) Reserve additions for Infill Drilling, Extensions and Improved Recovery are combined and reported as ‘Extensions and Improved Recovery’.

FUTURE DEVELOPMENT COSTS

The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserves categories noted below:

Future Development Costs

Year	Proved Reserves ($ millions)	Proved Plus Probable Reserves ($ millions)
2017	542	662
2018	530	639
2019	404	524
2020	151	279
2021	94	211
Remainder	187	441
Total: Undiscounted	1,908	2,755
Total: Discounted at 10% per Year	1,553	2,169

We expect to fund the development costs of the reserves through a combination of sources including funds from operations, proceeds from property dispositions, debt capacity, and if necessary, the issuance of Common Shares.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 17

Changes in forecast future development capital 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 plus probable undeveloped reserves on production at that time. Undiscounted future development costs (“FDC”) for proved plus probable undeveloped reserves increased $25 million compared to year-end 2015, to total $2.8 billion at year-end 2016. The change inFDC is mainly attributed to an increase in the number of undeveloped locations, offset by a decrease due to the disposition of Saskatchewan assets.

Estimates of reserves and future net revenues have been made assuming the development of each property, in respect of which the estimate is made, will occur, without regard to the likely availability to us of funding required for the development. There can be no guarantee that funds will be available or that we will allocate funding to develop all of the reserves attributed in the GLJ Report. Failure to develop those reserves would have a negative impact on future funds from operations.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenues to some degree depending upon the funding sources utilized. We do not anticipate that interest or other funding costs would make development of any property uneconomic.

UNDEVELOPED RESERVES

Undeveloped reserves are attributed by GLJ in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

The following tables disclose by each product type the volumes of proved and probable undeveloped reserves that were first attributed by GLJ in each of the most recent three financial years.

Proved Undeveloped Reserves

	Light Crude Oil and Medium Crude Oil (Mbbl)				Heavy Crude Oil (Mbbl)				Tight Oil(Mbbl)				ConventionalNatural Gas (Bcf)				Shale Gas(Bcf)
	First Attributed		Total at Year-End		First Attributed		Total at Year-End		First Attributed		Total at Year-End		First Attributed		Total at Year-End		First Attributed		Total at Year-End
2014		3,253		8,451		-		105		1,029		6,740		0.9		6.2		130.9		761.2
2015		507		5,988		-		84		3,008		7,712		0.5		5.1		166.8		776.7
2016		293		6,088		-		80		9,854		14,078		0.7		8.1		377.1		941.8
	Coal Bed Methane (Bcf)				NGLs (Mbbl)				Total (Mboe)
	First Attributed		Total at Year-End		First Attributed		Total at Year-End		First Attributed		Total at Year-End
2014	NMF			2.2		1,869		8,833		28,140		152,390
2015	NMF			1.2		3,795		15,470		35,205		159,755
2016		0		0		10,507		24,108		83,261		202,656

ARC Resources Ltd. | 2016 | Annual Information Form | Page 18

Probable Undeveloped Reserves

	Light Crude Oil and Medium Crude Oil (Mbbl)				Heavy Crude Oil (Mbbl)				Tight Oil(Mbbl)				ConventionalNatural Gas (Bcf)				Shale Gas(Bcf)
	First Attributed		Total at Year-End		First Attributed		Total at Year-End		First Attributed		Total at Year-End		First Attributed		Total at Year-End		First Attributed		Total at Year-End
2014		3,240		7,994		-		42		1,715		11,605		1.1		5.7		219.6		1,052.9
2015		1,752		10,083		-		29		3,911		11,449		1.4		8.4		195.0		1,034.5
2016		207		3,653		-		28		6,171		9,809		0.3		5.5		506.9		1,151.2
	Coal Bed Methane (Bcf)				NGLs (Mbbl)				Total (Mboe)
	First Attributed		Total at Year-End		First Attributed		Total at Year-End		First Attributed		Total at Year-End
2014	NMF			2.6		3,723		13,837		45,467		210,357
2015	NMF			2.0		5,747		19,169		44,148		214,882
2016		-		-		16,082		28,291		106,991		234,556

*NMF: Not Meaningful Figure

As of December 31, 2016, undeveloped reserves represented 48 per cent of total proved reserves and 59 per cent of proved plus probable reserves. Over 91 per cent of the proved plus probable undeveloped reserves are located in the Northeast BC core area. We have planned a program for the development of a portion of the undeveloped reserves in 2017 and 2018, focusing on the Dawson, Parkland/Tower, Sunrise, Attachie and Pouce Coupe areas.  ARC's 2017 capital program includes infrastructure spending for Dawson Phase III anticipated to be on-stream in late 2017, along with Parkland/Tower gas processing and liquids-handling facility expansion expected to come on-stream in late 2018. Front-end engineering and design work will also be initiated for the Sunrise Phase II gas processing facility expansion, the newest sanctioned project for Montney growth, expected to come on-stream midyear 2019.

The pace of development of the proved and probable undeveloped reserves (both in 2017 and 2018 as well as in years beyond 2018) is influenced by many factors, including the outcomes of the yearly drilling and reservoir evaluations, the price for oil and natural gas, and a variety of economic factors and conditions.

There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations or changing regulation and/or fiscal or environmental policy); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion in one zone may be delayed until the initial completion from a separate zone is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). For more information, see “Risk Factors – Risk Relating to Our Business and Operations”.

SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA

We have a significant amount of proved undeveloped and probable undeveloped reserves assigned to the NE BC Montney. Sophisticated and expensive technology and large capital expenditures are required to bring these undeveloped reserves into production. In addition, see Appendix C “Contingent Resource Estimates” for a discussion of risks which relate to the recovery of additional reserves and contingencies that prevent resources from being classified as reserves.

Degradation in future commodity price forecasts relative to the forecast in the GLJ Report would also have a negative impact on the economics and timing of the development of undeveloped reserves, unless significant reduction in the future costs of development are realized.

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The following table sets forth information respecting future abandonment and reclamation costs recognized in our audited consolidated financial statements for the year ended December 31, 2016 for surface leases, wells, facilities and pipelines for properties to which reserves have been attributed (aggregated at a property level):

Abandonment & Reclamation Costs(1) Escalated at 2.0%	Undiscounted ($ millions)		Discounted at 10%(2) ($ millions)
Total as at December 31, 2016		707.5		97.1
Anticipated to be paid in 2017		14.5		13.2
Anticipated to be paid in 2018		9.3		7.7
Anticipated to be paid in 2019		8.4		6.3

1) Abandonment and reclamation costs associated with liabilities associated with properties moved to held for sale at December 31, 2016 have been   excluded from this summary.

2) Costs have been discounted in our audited consolidated financial statements for the year ended December 31, 2016 at a liability-specific risk-free rate 2.3 per cent.

For more information with respect to our reclamation and abandonment obligations for properties with no attributed reserves, see “Statement of Reserves Data and Other Oil and Gas Information – Properties with no Attributed Reserves” in this Annual Information Form.

In addition, see “Further Information Respecting Abandonment Obligations” below.

FURTHER INFORMATION RESPECTING ABANDONMENTS OBLIGATIONS

We will be liable for our share of ongoing environmental obligations and for the ultimate reclamation of the properties held by us upon abandonment. We estimate that we have an interest in 3,799 net wells (4,407 net wells including the wells moved to liabilities associated with properties held for sale at December 31, 2016) that will require abandonment and/or reclamation over the next 60 years with the majority of payments being made in years 2065 to 2076. This net well count includes wells on properties with reserves attributed and without reserves attributed, including producing and non-producing oil wells, producing and non-producing natural gas wells, injection and disposal wells and wells that have been abandoned but not yet fully reclaimed. These ongoing environmental obligations are expected to be funded with funds from operations. At year-end 2015, we estimated that we had an interest in 4,988 net wells that would require abandonment or reclamation. The year-over-year reduction in well count is due to the combined result of divestitures, properties we intend to divest and have moved to assets held for sale, and reclamation certificates received on wells in 2016.

GLJ's forecast of well abandonment and reclamation costs of $462 million for all wells with proved plus probable reserves assigned are included in their estimate of future net revenue. GLJ’s estimate of future net revenue also includes abandonment and reclamation costs associated with properties that were moved to held for sale at December 31, 2016. Abandonment and reclamation costs for wells for which no reserves are assigned and for our facilities and pipelines are not included in GLJ’s estimate of future net revenue but they are considered in our calculation of abandonment and reclamation obligations.

We currently estimate that the future abandonment and reclamation obligations in respect of all of our properties (those properties with attributed reserves as well as those properties with no attributed reserves) will be approximately $725.9 million ($1.2 billion including the liability associated with properties moved to held for sale at December 31, 2016), calculated by escalating costs at two per cent per year (reflected in our audited consolidated financial statements as an asset retirement obligation of $378.9 million ($550 million including the liability associated with properties moved to held for sale at December 31, 2016) calculated by escalating costs at two per cent per year and discounting at a liability-specific risk-free rate of approximately 2.3 per cent). For more information, see Note 14 “Asset Retirement Obligations” of our audited consolidated financial statements for the year ended December 31, 2016 and the section in our Management's Discussion and Analysis under the heading "Asset Retirement Obligations and Reclamation Fund", which note and section are incorporated in this Annual Information Form by reference and are found on our SEDAR profile at www.sedar.com. At December 31, 2016, ARC classified $171.1 million of ARO associated with certain non-core assets in Alberta as held for sale, which is associated with 608 net wells. During 2016, $13.0 million of actual expenditures were incurred on abandonment and reclamation activities.

We have committed to a restricted reclamation fund associated with the 2005 acquisition of the Redwater property pursuant to which ARC agreed with the vendor of the Redwater property to contribute to such trust certain minimum amounts, totaling approximately $110 million over a 50 year period, to fund future environmental and reclamation obligations in respect of the Redwater properties, or to expend certain minimum amounts towards discharging these obligations. The restricted reclamation fund commenced in 2006 with an initial contribution of $6.1 million. In

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accordance with the fund agreement, ARC has contributed total funds of $51.4 million to the restricted reclamation fund as at December 31, 2016. Contributions to the fund will continue at a declining rate through 2055. The balance of the restricted reclamation fund was $36.5 million at December 31, 2016.

We estimate the costs to abandon and reclaim all our shut-in and producing wells, pipelines and facilities. No estimate of salvage value is netted against the estimated cost. Our model for estimating the amount and timing of future abandonment and reclamation expenditures was created on an operating area level. Estimated expenditures for each operating area are benchmarked from numerous sources including the provincial regulatory agencies, industry peer groups, third-party engineering firms and actual data from our operations. All wells, pipelines, facilities and associated costs are then assigned to a specific geographic region which is consistent with the methodology used by the Alberta Energy Regulator.

The provision for site restoration and abandonment is based on current legal and regulatory requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, market conditions, discovery and analysis of site conditions and changes in technology. For more information reference is made to Note 5 “Management Judgments and Estimation Uncertainty” of our audited consolidated financial statements for the year ended December 31, 2016, which is incorporated by reference in this Annual Information Form and is found on our SEDAR profile at www.sedar.com.

Abandonment and reclamation costs have been estimated over a 60 year period. Facility abandonment and reclamation costs are scheduled to be incurred in the year following the end of the reserves life of the associated reserves.

CORE OPERATING AREAS

The following is a description of our principal oil and natural gas core areas as at December 31, 2016. Reserves amounts are stated at December 31, 2016, based on escalated cost and price assumptions as evaluated in the GLJ Report prepared by GLJ (see “Statement of Reserves Data and Other Oil and Gas Information”). Information in respect of gross and net acres and well counts are as at December 31, 2016, and information in respect of production is for the year ended December 31, 2016 except where indicated otherwise. Due to the fact that we have been active at acquiring additional interests in our core areas (and divesting assets in our non-core properties), the working interest in gross/net acres and wells at December 31, 2016 may not directly correspond to the stated production for the year, which only includes production after (or up to) the date the interests were acquired (or divested) by us. The estimate of reserves for individual properties and/or core areas may not reflect the same confidence level as estimates for all properties, due to the effects of aggregation.

The core areas described below are located in the Western Canadian Sedimentary Basin and within the Canadian provinces of British Columbia and Alberta. The table below includes company gross production and company gross reserves for all producing assets in 2016 including ARC’s Saskatchewan assets, which were divested of in the fourth quarter of 2016. Except as set forth under the heading “Statement of Reserves Data and Other Oil and Gas Information – Undeveloped Reserves”, there are no other material districts to which reserves have been attributed that are capable of producing but which are not producing at December 31, 2016 and there are no material statutory or mandatory relinquishments, surrenders, back-ins or changes in ownership provisions. When determining gross and net acreage for two or more lease agreements covering the same lands but different rights, the acreage is reported for each lease agreement.

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2016 Company Gross Production and Company Gross Reserves

	Light Crude Oil and Medium Crude Oil and Tight Oil (1)		Heavy Crude Oil (1)		Natural Gas (1)(2)		NGLs (1)		Total Oil Equivalent Production (1)		Proved Reserves		Proved Plus Probable Reserves		Proved Plus Probable Reserves
Core Area	(bbl/d)		(bbl/d)		(MMcf/d)		(bbl/d)		(boe/d)		(Mboe)		(Mboe)		(%)
NE British Columbia		7,299		-		392.5		4,899		77,616		313,816		575,963		78
Northern Alberta		6,555		1		65.3		2,070		19,514		43,436		69,233		9
Pembina		6,906		346		12.5		630		9,972		51,057		69,306		9
South Central Alberta		2,926		258		3.5		153		3,927		17,619		22,231		3
Southeast SK (3)		6,921		-		0.8		137		7,185		-		-		-
Total (4)		30,608		604		474.8		7,889		118,214		425,927		736,733		100

1) Production volumes as disclosed above are “gross production” which is our interest (operated and non-operated) in production before deduction of royalties and without including any royalty interests to us. These volumes differ from the “company interest production” volumes disclosed in this Annual Information Form under “ARC Resources Ltd. - Development of our Business” and “Statement of Reserves Data and Other Oil and Gas Information – Production History” as well as in our audited consolidated financial statements for the year ended December 31, 2016 and the related Management’s Discussion and Analysis which is our interest (operated and non-operated) in production before deduction of royalties inclusive of royalty interests.

2) Natural gas production includes production from Conventional Natural Gas, Shale Gas and Coal Bed Methane.

3) During the fourth quarter of 2016, ARC disposed of the remaining assets in this district.

4) May not add due to rounding.

Core Operating Areas

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Northeast British Columbia

ARC’s assets in Northeast British Columbia are predominantly located in the Montney formation, which is recognized as a world class resource play.  Production from the Montney includes dry natural gas, liquids-rich natural gas and light oil dependent on the location in the fairway and on the layer being produced.  ARC’s Montney assets span all three of these product types.  ARC is one of the largest operators in the region with an average working interest of 90 per cent in approximately 229,695 gross hectares (206,577 net hectares), which includes land holdings of 657 net Montney sections in British Columbia. Key operating areas include Dawson, Parkland/Tower and Sunrise.  Future growth areas include Septimus, Sundown, Attachie, Red Creek and Blueberry. The Montney is a key growth area for ARC with significant potential for continued reserves and production additions. In 2016, the gross proven plus probable reserves assigned by GLJ for northeast British Columbia were 576 MMboe or 78 per cent of the total proven plus probable reserves of the Corporation. The GLJ Report estimates the drilling of 386 proved undeveloped and probable locations will be needed to achieve production of these reserves.

During 2016, ARC continued the successful development and delineation of various properties within this core area, spending $343 million or 76 per cent of its 2016 capital program (excluding land purchases) in the region. ARC drilled 50 gross operated wells in 2016 with an average working interest of 99 per cent. ARC owns and operates approximately 300 MMcf per day of natural gas and 15,600 barrels per day of liquids processing capacity in the region, and during the year continued construction on the Dawson Phase III gas processing and liquids handling facility, which is expected to come on-stream in late 2017. Dawson Phase III is designed to process 90 MMcf per day of natural gas and 7,500 barrels per day of liquids (approximately 50 per cent condensate handling).

Northern Alberta

ARC’s holdings in Northern Alberta are characterized by long-life reserves which have significant potential for continued growth and development. ARC has an average working interest of 79 per cent in the area with approximately 290,450 gross hectares (229,270 net hectares), which includes land holdings of 514 net Montney sections. Key properties in the area are Ante Creek and Pouce Coupe. ARC’s holds 382 net Montney sections at Ante Creek, which is located within the oil-prone window of the Montney formation and produces a mixture of oil, natural gas and natural gas liquids. In 2016, GLJ assigned gross proved reserves of 43 MMboe and gross proved plus probable reserves of 69 MMboe of oil, natural gas and natural gas liquids to the Northern Alberta core area, representing nine per cent of ARC’s total gross proved plus probable reserves. The GLJ Report estimates the drilling of 90 operated proved undeveloped and probable locations will be needed to achieve production of these reserves.

During 2016, ARC spent $40 million, or nine per cent of its 2016 capital program (excluding land) in Northern Alberta.  ARC drilled six gross operated wells in 2016, with an average working interest of 100 per cent. The majority of spending was at Ante Creek, where ARC spent $30 million, which included drilling and completing four gross operated crude oil wells.

Pembina

ARC has been a core owner in Pembina since its inception in 1996 and today is one of the largest operators in the area. The field is characterized by its long reserve life, attractive netbacks, high quality oil, and proximity to refining facilities. ARC has an average working interest of 79 per cent in approximately 83,229 gross hectares (65,634 net hectares.Key properties held by ARC in the area include, the North Pembina Cardium Unit (100 per cent unit interest), MIPA (86.8 per cent working interest), Berrymoor Cardium Unit (85.0 per cent unit interest), Buck Creek (91.4 per cent working interest), and Lindale Cardium Unit (62.6 per cent unit interest). In 2016, GLJ assigned gross proved reserves of 51 MMboe and gross proved plus probable reserves of 69 MMboe of oil, natural gas and natural gas liquids to this core area, representing nine per cent of ARC’s total gross proved plus probable reserves. The GLJ Report estimates the drilling of 78 operated proved undeveloped and probable locations will be needed to achieve production of these reserves.

During 2016, ARC spent $32 million or approximately seven per cent of the 2016 capital program (excluding land purchases) in the area, drilling a total of eight gross operated Cardium horizontal oil wells with an average working interest of 100 per cent. ARC successfully added to its working interest in the area in 2016, with combined acquisitions increasing annual average production by approximately 1,400 boe per day.

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South Central Alberta

ARC’s South Central Alberta assets produce predominately high-quality crude oil.  ARC has an average working interest of 80 per cent in approximately 31,615 gross hectares (25,450 net hectares) in the region. Redwater is the largest property in this area producing approximately 3,000 boe per day in 2016. GLJ assigned gross proved reserves of 18 MMboe and gross proved plus probable reserves of 22 MMboe of oil, natural gas and natural gas liquids to the South Central AB core area, representing threeper cent of ARC’s total gross proved plus probable reserves. The GLJ Report estimates the drilling of 15 operated proved undeveloped and probable locations will be needed to achieve the production of these reserves.

During 2016, ARC spent $14 million or approximately three per cent of the 2016 capital program (excluding land purchases), on the construction of a new gas plant at Redwater. The new facility was brought on-stream in the third quarter of 2016, and is expected to significantly reduce greenhouse gas emissions and operating costs.

In the fourth quarter of 2016, ARC divested of its Saskatchewan assets. Prior to divestment ARC invested approximately $10 million on capital activities in the area during 2016. Divested production accounted for approximately 7,228 boe per day on an annual basis.

CONTINGENT RESOURCE ESTIMATES

ARC engaged GLJ to provide an updated evaluation of, among other things,our Contingent Resources (as defined in Appendix C attached to this Annual Information Form) effective December 31, 2016, for our working interest in our NE BC Montney properties, including lands at Pouce Coupe across the provincial border in Alberta. These Contingent Resources are set forth and described in Appendix C attached to this Annual Information Form.

OIL AND GAS WELLS

The following tables set forth the number and status of wells in which we had a working interest as at December 31, 2016.

By Core Area	Oil Wells (1)								Natural Gas Wells (2)
	Producing				Non-Producing				Producing				Non-Producing
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
NE British Columbia		92		91		11		10		370		341		145		133
Northern Alberta		644		335		427		140		415		102		151		63
Pembina		1,282		965		483		275		63		20		41		19
South Central Alberta		487		473		95		90		30		14		18		10
Total (3)		2,505		1,864		1,016		515		878		477		355		225

By Province	Oil Wells (1)								Natural Gas Wells (2)
	Producing				Non-Producing				Producing				Non-Producing
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Alberta		2,413		1,773		1,005		505		508		136		210		92
British Columbia		92		91		11		10		370		341		145		133
Total (3)		2,505		1,864		1,016		515		878		477		355		225

1) Includes light crude oil and medium crude oil wells, heavy crude oil wells and tight oil wells.

2) Includes conventional natural gas wells and shale gas wells.

3) Total well count differs from well count provided in ARO, as this table excludes abandoned, water source, water injection and disposal wells.

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PROPERTIES WITH NO ATTRIBUTABLE RESERVES

The following table sets out by district our undeveloped land holdings as at December 31, 2016.

Undeveloped Hectares

	Gross		Net
NE British Columbia		150,794		137,069
Northern Alberta		183,478		134,703
Pembina		40,705		5,574
South Central Alberta		10,788		7,434
Total		385,765		284,780

Undeveloped hectares are lands that have not been assigned reserves; however, in certain of our undeveloped lands, reserves may have been assigned in shallower formations. Undeveloped hectares are mineral agreement specific. The table above includes vertically stacked agreements within the same areal footprint.

ARC has no material work commitments related to our undeveloped hectares in 2017. There are no material expiries in our core holdings in 2017.

Significant Factors or Uncertainties for Properties with No Attributed Reserves

The following table sets forth information respecting future abandonment and reclamation costs, recognized in our audited consolidated financial statements for the year ended December 31, 2016 for surface leases, wells, facilities and pipelines for our properties to which reserves have not been attributed (aggregated at a property level):

Abandonment & Reclamation Costs Escalated at 2.0%	Undiscounted ($ millions)		Discounted at 10% ($ millions)
Total as at December 31, 2016		18.4		5.8
Anticipated to be paid in 2017		1.3		1.2
Anticipated to be paid in 2018		0.6		0.5
Anticipated to be paid in 2019		0.4		0.3

1) Costs have been discounted in our audited consolidated financial statements for the year ended December 31, 2016 at a liability-specific risk-free rate 2.3 per cent.

For information with respect to our reclamation and abandonment obligations for our properties to which reserves have been attributed, see “Statement of Reserves Data and Other Oil and Gas Information – Undeveloped Reserves” in this Annual Information Form.

In addition, see “Statement of Reserves Data and Other Oil and Gas Information – Further Information Respecting Abandonment Obligations” in this Annual Information Form.

FORWARD CONTRACTS

We are exposed to market risks resulting from fluctuations in commodity prices, power prices, foreign exchange rates and interest rates in the normal course of operations. ARC maintains a risk management program to reduce the volatility of revenues, increase the certainty of funds from operations, and to protect acquisition and development economics.

We may also potentially be exposed to losses in the event of default by the counterparties to these derivative instruments. We manage this risk by diversifying our derivative portfolio among a number of financially sound counterparties, including counterparties among our lending syndicate, and by monitoring their ongoing credit risks.

ARC’s risk management program is governed by certain guidelines approved by the Board of Directors. These guidelines permit hedging up to a maximum of 55 per cent of guided production on a boe basis for up to two years with a maximum of 70 per cent for any one commodity. The guidelines permit additional hedging of 25 per cent of forecasted production beyond year two and up to five years. Further to these authorizations, the Board of Directors may approve hedging higher percentages of guided production or longer term hedging transactions to mitigate risks relating to, and protecting the economics of major capital expenditures, including acquisitions. The Risk Committee of

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the Board of Directors reviews policies, procedures and provides oversight to management in the areas of financial and business risks including activities related to our hedging program.

A summary of financial and physical contracts in respect of hedging activities can be found in Note 16 “Financial Instruments and Market Risk Management” to our audited consolidated financial statements for the year ended December 31, 2016 and in the section under the heading “Risk Management” in our Management's Discussion and Analysis for the year ended December 31, 2016 which have been filed on our SEDAR profile at www.sedar.com, and both of which the note and section are incorporated in this Annual Information Form by reference.

TAX HORIZON

We expect to allocate our funds from operations towards a portion of capital expenditures, periodic debt repayments, site reclamation expenditures, potential net acquisitions of land and production, and cash payments to Shareholders in the form of dividends. Taxable income varies depending on total income and expenses and varies with changes to commodity prices, costs, claims for both accumulated tax pools and tax pools associated with current year expenditures, acquisitions, and dispositions.

ARC has accumulated $1.6 billion of income tax pools for federal tax purposes as at December 31, 2016. In 2016, ARC recognized current income taxes of $21.7 million related to current period taxable income, and $3.7 million of income taxes related to adjustments for prior taxation years. For 2017, ARC expects to recognize current income taxes between five and ten per cent of funds from operations; however, this will be dependent on the commodity price environment and capital spending. For more information, please see Note 17 “Income Taxes” in our audited consolidated financial statements for the year ended December 31, 2016, which note is incorporated by reference in this Annual Information Form and is found on our SEDAR profile at www.sedar.com.

CAPITAL EXPENDITURES

The following table summarizes capital expenditures (net of incentives and net of certain acquisitions and dispositions, and including capitalized general and administrative expenses) related to our activities for the year ended December 31, 2016:

2016 Capital Expenditures

($ millions)	NE British Columbia		Northern Alberta			Pembina		South Central Alberta			SE Sask (5)			Corporate		Total
Property Acquisition  (Disposition) Costs, Net (1)
Proved Properties		29.1		(17.7	)		143.4		(3.5	)		(683.9	)		-		(532.6	)
Undeveloped Properties		0.1		-			-		-			-			-		0.1
Exploration Costs (2)		38.0		-			-		-			-			-		38.0
Development Costs (3)		306.4		41.7			32.2		14.4			10.4			-		405.1
Corporate Capital Costs (4)		2.0		-			-		-			-			11.0		13.0
Total		375.6		24.0			175.6		10.9			(673.5	)		11.0		(76.4	)

1) Represents acquisition costs net of dispositions and property swaps. Acquisition value is net of post-closing adjustments. Disposition value represents proceeds and adjustments to proceeds from divestitures.

2) Represents asset additions that have been determined by management to be in the exploration and evaluation stage and includes costs of land acquired ($0.3 million).

3) Represents additions to oil and gas development and production assets and administrative assets and includes costs of land acquired ($2.4 million).

4) Represents administrative assets allocated on a corporate level.

5) During the fourth quarter of 2016, ARC disposed of all remaining assets in this district.

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EXPLORATION AND DEVELOPMENT ACTIVITIES

The following tables set forth the gross and net development wells that we participated in during the year ended December 31, 2016.

By Core Area	Development Wells (1)				Exploratory Wells(1)				Total (1)
	Gross		Net		Gross		Net		Gross		Net
NE British Columbia		48		48.00		2		1.50		50		49.50
Northern Alberta		6		6.00		-		-		6		6.00
Pembina		11		8.03		-		-		11		8.03
SE Saskatchewan (2)		2		0.14		-		-		2		0.14
Total		65		62.17		2		1.50		69		63.67

By Well Type	Development Wells (1)				Exploratory Wells(1)				Total (1)
	Gross		Net		Gross		Net		Gross		Net
Crude Oil		40		35.17		-		-		40		35.17
Natural Gas		27		27.00		2		1.50		29		28.50
Total		65		62.17		2		1.50		69		63.67

1) Number of wells based on rig release dates.

2) ARC disposed of its SE Saskatchewan assets in the fourth quarter of 2016.

PRODUCTION ESTIMATES

The following tables set out the GLJ forecast of the volume of production estimated for the year ended December 31, 2017 which is reflected in the estimate of gross proved reserves and gross probable reserves disclosed in the tables contained under “Statement of Reserves Data and Other Oil and Gas Information ‑ Disclosure of Reserves Data”.

TOTAL PROVED
	Light Crude Oil & Medium Crude Oil (bbl/d)				Heavy Crude Oil(bbl/d)				Tight Oil(bbl/d)				Conventional Natural Gas(Mcf/d)				Shale Gas(Mcf/d)				NGLs(bbl/d)				Total(boe/d)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Dawson		-		-		-		-		-		-		-		-		172,993		151,887		953		831		29,785		26,145
Other Properties		12,399		11,492		396		584		10,670		8,765		25,074		23,058		265,760		243,083		6,217		4,944		78,154		70,142
Total Proved		12,399		11,492		396		584		10,670		8,765		25,074		23,058		438,752		394,970		7,169		5,774		107,939		96,287

TOTAL PROBABLE
	Light Crude Oil & Medium Crude Oil(bbl/d)				Heavy Crude Oil(bbl/d)				Tight Oil(bbl/d)				Conventional Natural Gas(Mcf/d)				Shale Gas(Mcf/d)				NGLs(bbl/d)				Total(boe/d)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Dawson		-		-		-		-		-		-		-		-		40,682		38,645		227		216		7,008		6,656
Other Properties		447		393		4		23		2,639		2,071		731		665		36,756		33,608		1,175		1,011		10,513		9,210
Total Probable		447		393		4		23		2,639		2,071		731		665		77,438		72,253		1,402		1,227		17,520		15,867

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TOTAL PROVED PLUS PROBABLE
	Light Crude Oil & Medium Crude Oil (bbl/d)				Heavy Crude Oil(bbl/d)				Tight Oil(bbl/d)				Conventional Natural Gas(Mcf/d)				Shale Gas(Mcf/d)				NGLs(bbl/d)				Total (boe/d)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Dawson		-		-		-		-		-		-		-		-		213,674		190,532		1,180		1,046		36,793		32,802
Other Properties		12,846		11,885		400		607		13,309		10,836		25,805		23,723		302,516		276,691		7,392		5,955		88,666		79,352
Total Proved + Probable		12,846		11,885		400		607		13,309		10,836		25,805		23,723		516,190		467,223		8,572		7,001		125,459		112,153

The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

PRODUCTION HISTORY

The following tables summarize certain information in respect of our production, product prices received, royalties paid, operating expenses and resulting netbacks for the periods indicated below:

Production History	Quarter Ended 2016								Year Ended
	Mar 31		June 30		Sept 30		Dec 31		2016
Average Daily Production (1)
Light and Medium Crude Oil (bbl/d) (2)		34,367		31,217		28,908		29,184		30,906
Heavy Oil (bbl/d)		485		485		734		701		604
Gas (MMcf/d) (3)		489.7		467.5		466.7		478.4		475.6
NGLs (bbl/d) (4)		7,761		8,069		7,783		7,987		7,900
Condensate (bbl/d)		3,442		3,733		3,562		3,767		3,626
NGLs (bbl/d) (5)		4,319		4,336		4,221		4,220		4,274
Total (boe/d)		124,224		117,695		115,205		117,611		118,671
Average Net Production Prices Received
Light and Medium Crude Oil ($/bbl) (2)		39.04		53.03		52.90		59.59		50.69
Heavy Oil ($/bbl)		10.46		38.15		33.79		42.89		32.62
Gas ($/Mcf) (3)		2.05		1.39		2.35		3.10		2.23
NGLs ($/bbl) (4)		50.49		64.80		63.48		79.74		64.83
Condensate ($/bbl)		42.07		51.20		50.81		58.97		50.98
NGLs ($/bbl) (5)		8.42		13.60		12.67		20.77		13.85
Total ($/boe) (6)		20.45		21.94		25.05		30.67		24.49
Royalties Paid
Light and Medium Crude Oil ($/bbl) (2)		4.48		5.87		5.42		7.00		5.65
Heavy Oil ($/bbl)		0.83		1.65		1.07		1.34		1.22
Gas ($/Mcf) (3)		0.03		-		0.10		0.08		0.05
NGLs ($/bbl) (4)		8.90		12.07		11.65		14.47		11.27
Condensate ($/bbl)		7.26		9.59		9.24		8.67		8.70
NGLs ($/bbl) 5)		1.64		2.48		2.41		3.80		2.57
Total ($/boe)		1.62		1.97		2.16		2.47		2.05
Operating Expenses (7)(8)
Light and Medium Crude Oil ($/bbl) (2)		12.36		12.12		14.47		14.02		13.11
Heavy Oil ($/bbl)		14.03		13.89		11.74		13.47		13.14
Gas ($/Mcf) (3)		0.57		0.68		0.78		0.69		0.69
NGLs ($/bbl) (4)		12.78		12.81		14.63		12.03		12.24
Condensate ($/bbl)		6.82		6.37		7.09		5.49		5.75
NGLs ($/bbl) (5)		5.96		6.44		7.54		6.54		6.49
Total ($/boe)		6.10		6.41		7.37		6.77		6.65
Transportation Paid
Light and Medium Crude Oil ($/bbl) (2)		2.77		2.84		2.50		2.67		2.70
Heavy Oil ($/bbl)		0.79		0.76		0.51		0.54		0.63
Gas ($/Mcf) (3)		0.29		0.28		0.28		0.32		0.29
NGLs ($/bbl) (4)		9.02		8.52		9.22		10.59		9.33
Condensate ($/bbl)		2.49		2.00		2.20		2.64		2.33
NGLs ($/bbl) (5)		6.53		6.52		7.02		7.95		7.00
Total ($/boe)		2.20		2.19		2.08		2.32		2.20

ARC Resources Ltd. | 2016 | Annual Information Form | Page 28

Production History	Quarter Ended 2016											Year Ended
	Mar 31			June 30			Sept 30			Dec 31		2016
(Loss)/Gain on Commodity Contracts
Light and Medium Crude Oil ($/bbl) (2)		8.14			4.71			4.80			2.00		5.04
Heavy Oil ($/bbl)		-			-			-			-		-
Gas ($/Mcf) (3)		0.96			1.22			0.86			0.63		0.92
NGLs ($/bbl) (4)		-			-			-			-		-
Condensate ($/bbl)		-			-			-			-		-
NGLs ($/bbl) (5)		-			-			-			-		-
Total ($/boe)		6.04			6.10			4.67			3.08		4.98
Netback Received (9)
Light and Medium Crude Oil ($/bbl) (2)		27.57			36.91			35.31			37.90		34.27
Heavy Oil ($/bbl)		(5.19	)		21.85			20.47			27.54		17.63
Gas ($/Mcf) (3)		2.12			1.65			2.05			2.64		2.12
NGLs ($/bbl) (4)		19.79			31.40			27.98			44.65		31.99
Condensate ($/bbl)		25.50			33.24			32.28			42.17		34.20
NGLs ($/bbl) (5)		(5.71	)		(1.84	)		(4.30	)		2.48		(2.21	)
Total ($/boe)		16.57			17.47			18.11			22.19		18.57

1) Before deduction of royalties and including royalty interests.

2) Light and Medium Crude Oil as defined by ARC in external reporting includes light crude oil, medium crude oil and tight oil.

3) Gas as defined by ARC in external reporting includes conventional natural gas, shale gas and coal bed methane.

4) NGLs as defined by GLJ which includes condensate, butane, ethane and propane.

5) NGLs or natural gas liquids as defined by ARC in external reporting includes butane, ethane and propane but excludes condensate.

6) Total average price received includes other income from standard business activities including interest earned on ARC’s reclamation fund.

7) Operating expenses are composed of direct costs incurred to operate both oil and gas wells. A number of assumptions have been made in allocating these costs between oil, natural gas, condensate and natural gas liquids production.

8) Operating recoveries associated with operated properties were excluded from operating costs and accounted for as a reduction to general and administrative costs.

9) Netbacks are calculated by subtracting royalties, operating expenses, transportation costs, and realized (losses)/gains on commodity contracts from revenues. Netbacks before hedging can be found in Table 16 and 16a “Netbacks prior to hedging” under the section Operating Netbacks of our Management’s Discussion and Analysis for the year ended December 31, 2016 which has been filed on our SEDAR profile at www.sedar.com.

The Northeast British Columbia, Northern Alberta, Pembina, SE Saskatchewan and South Central Alberta core areas account for approximately 66 per cent, 16 per cent, nine per cent, six percent and three per cent, respectively, of the total production disclosed above. For more information, see “Statement of Reserves Data and Other Oil and Gas Information – Other Oil and Gas Information”. ARC's SE Saskatchewan properties were sold in the fourth quarter of 2016.

MARKETING ARRANGEMENTS

Below are details on marketing arrangements for our natural gas, natural gas liquids and crude oil production. For more information on financial contractual obligations relating to ARC’s transportation agreements please see Note 20 “Commitments and Contingencies” in our audited consolidated financial statements for the year ending December 31, 2016, which note is incorporated by reference in this Annual Information Form and is found on our SEDAR profile at www.sedar.com.

Natural Gas

During 2016, ARC continued its marketing strategy of maintaining a high level of direct control and diversification of marketing and transportation arrangements for our natural gas production.

The average natural gas price we received during 2016 was $2.23 per Mcf before hedging as compared to $2.88 per Mcf before hedging for 2015. This price was achieved with a portfolio mix that on average through the year, before hedging, received AECO index based pricing for 72 per cent, Western Canadian Station 2 index based pricing for 12 per cent, Midwest based pricing for 14 percent and Pacific Northwest based pricing for two per cent of total production.

Our natural gas sales portfolio is directed towards liquid markets and pricing terms that allow us to reduce price volatility and to stabilize the revenue stream. We also strive for a high utilization of contracted pipeline and processing capacity.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 29

Crude Oil and Natural Gas Liquids

Our liquids production in 2016 was comprised of approximately 52 per cent light quality crude oil (greater than 35° API), 25 per cent medium quality crude oil (25^o to 35^o API), one per cent heavy quality crude (less than 25^o API) and 22 per cent condensate and natural gas liquids.

During 2016, our average sales prices before hedging were $50.69 per barrel for light and medium crude oil, $32.62 per barrel for heavy crude oil and $30.89 per barrel for natural gas liquids including free condensate; these prices compare to 2015 prices of $53.94 per barrel for light and medium crude oil, $39.70 per barrel for heavy crude oil and $31.12 per barrel for natural gas liquids including free condensate.

ARC is strategically aligned with its crude oil purchasers which allowed us to be protected against varying degrees of price volatility in the market. See “Risk Factors – Risk Relating to Our Business and Operations – Market Access Constraints and Transportation Interruptions’.

Our crude oil is sold under contracts of varying terms of up to one year, based on market sensitive pricing terms. The majority of ARC’s natural gas liquids are sold on multi-year contracts at market-based pricing. Industry pricing benchmarks for crude oil and natural gas liquids are continuously monitored to ensure optimal netbacks.

CORPORATE SOCIAL RESPONSIBILITY

ARC is committed to operating in a responsible manner and integrating principles of responsible development into all parts of our business. Our Corporate Code of Conduct, Environmental and Health and Safety Policies guide our activities in these areas. These policies are available on our website at www.arcresources.com.

We published our biennial Sustainability Report in August 2016, detailing our efforts and performance in environmental management, health and safety, leadership culture, community investment, stakeholder engagement and corporate governance. The report can be viewed at www.arcresponsibility.com.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 30

SHARE CAPITAL OF ARC RESOURCES

The authorized capital of ARC Resources is an unlimited number of Common Shares without nominal or par value (defined in this Annual Information Form as “Common Shares”) and 50,000,000 preferred shares without nominal or par value issuable in series of which 353,286,339 Common Shares and no preferred shares are outstanding as at December 31, 2016.

The following is a summary of the rights, privileges, restrictions and conditions which attach to the securities of ARC Resources.

COMMON SHARES

Holders of Common Shares are entitled to notice of, to attend and to one vote per share held at any meeting of the Shareholders of the Corporation (other than meetings of a class or series of shares of the Corporation other than the Common Shares as such).

Holders of Common Shares are entitled to receive dividends as and when declared by the Board of Directors of the Corporation on the Common Shares as a class, subject to prior satisfaction of all preferential rights to dividends attached to shares of other classes of shares of the Corporation ranking in priority to the Common Shares in respect of dividends.

Holders of Common Shares are entitled in the event of any liquidation, dissolution or winding-up of the Corporation, whether voluntary or involuntary, or any other distribution of the assets of the Corporation among its Shareholders for the purpose of winding-up its affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of shares of the Corporation ranking in priority to the Common Shares in respect of return of capital on dissolution, to share rateably, together with the holders of shares of any other class of shares of the Corporation ranking equally with the Common Shares in respect of return of capital on dissolution, in such assets of the Corporation as are available for distribution.

PREFERRED SHARES

Preferred shares may at any time or from time-to-time be issued in one or more series. Before any shares of a particular series are issued, the Board shall, by resolution, fix the number of shares that will form such series and shall, subject to the limitations set out in ARC Resources' articles, by resolution fix the designation, rights, privileges, restrictions and conditions to be attached to the preferred shares of such series, including, but without in any way limiting or restricting the generality of the foregoing, the rate, amount or method of calculation of dividends thereon, the time and place of payment of dividends, the consideration for and the terms and conditions of any purchase for cancellation, retraction or redemption thereof, conversion or exchange rights (if any), and whether into or for securities of ARC Resources or otherwise, voting rights attached thereto (if any), the terms and conditions of any share purchase or retirement plan or sinking fund, and restrictions on the payment of dividends on any shares other than preferred shares or payment in respect of capital on any shares in the capital of ARC Resources or creation or issue of debt or equity securities. Notwithstanding the foregoing, other than in the case of a failure to declare or pay dividends specified in any series of preferred shares, the voting rights attached to the preferred shares shall be limited to one vote per preferred share at any meeting where the preferred shares and Common Shares vote together as a single class.

Any preferred shares of ARC Resources are intended to provide future financing flexibility and are not intended to be used to block any takeover bid for ARC Resources. ARC Resources confirms that it will not, without prior shareholder approval, issue any preferred shares for any anti-takeover purpose.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 31

OTHER INFORMATION RELATING TO OUR BUSINESS

BORROWING

ARC borrows funds periodically to finance the purchase of properties, for capital expenditures or for other financial obligations or expenditures in respect of properties held by us or for working capital purposes. ARC’s long-term strategy is to target net debt to annualized funds from operations between one to 1.5 times annualized funds from operations and less than 20 per cent of total capitalization over the long-term (see Note (1) in the section “ARC Resources Ltd. – Strategy” in this Annual Information Form). The level of borrowing is assessed on a weekly basis by management and is subject to quarterly reviews by the Board of Directors of ARC Resources.

Our borrowings may be comprised of both a bank credit facility and long-term notes issued to major financial institutions. We may choose to repay a portion of our debt from one source and borrow from other parties in order to reduce borrowing costs and provide more financial flexibility.

As at December 31, 2016, we had credit facilities consisting of a Cdn$950 million, financial covenant based credit facility with a syndicate of major chartered banks, a Cdn$40 million working capital facility with our agent bank, a Cdn$15 million letter of credit facility with our agent bank, a Cdn$25 million letter of credit facility with another major chartered bank and member of the syndicate, and US$734.4 million and Cdn$40.0 million of senior notes outstanding. An additional amount of US$160.6 million of senior notes was available to be issued pursuant to a US$350 million Master Shelf Agreement with a large insurance company (the “Master Shelf”). ARC had a net debt balance of Cdn$356.5 million outstanding at December 31, 2016, comprised of Cdn$1,026.0 million of long-term debt and a working capital surplus of Cdn$669.5 million.

Borrowings under the syndicated credit facility bear interest at bank prime or, at ARC's option, Canadian dollar bankers' acceptances or U.S. dollar LIBOR loans plus a stamping fee. At the option of ARC, the lenders will review the credit facility each year and determine whether they will extend the revolving four year period for another year. In the event the credit facility is not extended at any time before the maturity date, the loan will become repayable on the maturity date. On November 23, 2016, the credit facility was extended for another year at currentpricing terms of the existing facility. The current maturity date of the credit facility is November 6, 2020.

ARC has the option to negotiate a rate and term and draw the remaining credit capacity pursuant to the Master Shelf at any time. This option was renewed on September 25, 2014 and expires on September 25, 2017. ARC Resources may issue senior notes at a rate equal to the related U.S. treasuries corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. The senior notes outstanding were issued in 8 tranches and bear interest at a fixed rate. Each tranche requires certain repayments of principal prior to the final maturity thereof.

The following are significant financial covenants governing the revolving credit facilities:

— Long-term debt and letters of credit not to exceed 3.25 trailing 12 month net income before non-cash items, income tax and interest expense;

— Long-term debt, letters of credit and subordinated debt not to exceed four times trailing 12 month net income before non-cash items, income tax and interest expense; and

— Long-term debt and letters of credit not to exceed 50 per cent of Shareholders' equity and long-term debt, letters of credit and subordinated debt.

ARC is in compliance in all material respects with the terms of the agreements governing the credit facilities described above, and has maintained this status throughout the Company’s 20 year history.

The credit facilities and senior notes rank equally and contain provisions which restrict the payment of dividends to Shareholders, in the event of the occurrence of certain events of default. The syndicated credit agreement, the note agreements and master shelf agreement are described in this Annual Information Form under “Material Contracts” and have been filed on our SEDAR profile at www.sedar.com. For more information, reference is made to Note 13

ARC Resources Ltd. | 2016 | Annual Information Form | Page 32

 “Long-term Debt” of our audited consolidated financial statements for the year ended December 31, 2016, which note is incorporated by reference in this Annual Information Form and is found on our SEDAR profile at www.sedar.com.

See “Risk Factors – Risk Relating to Our Business and Operations”.

STOCK DIVIDEND PROGRAM AND DIVIDEND REINVESTMENT PLAN

On February 8, 2017, ARC announced the elimination of the Dividend Reinvestment Plan (“DRIP”) and the Stock Dividend Plan (“SDP”).  Elimination of both programs will apply to the April 17, 2017 dividend payment to Shareholders on record on March 31, 2017. The ex-dividend date is March 29, 2017. Shareholders that were enrolled in either the DRIP or SDP will now automatically receive dividend payments in the form of cash.

Prior to elimination of these programs, the SDP enabled Shareholders to receive dividends in the form of Common Shares of ARC in lieu of receiving a cash dividend on the dividend payment date. Common Shares issued under the SDP were issued at the prevailing market price, as defined under the SDP, with no broker fees or commissions. The SDP was generally available to most Shareholders and is expected to provide many Shareholders with Canadian income tax treatment that is more favourable than the DRIP, which is described below.

The DRIP enabled Canadian Shareholders to have their dividends reinvested into additional Common Shares of ARC. Common Shares issued under the DRIP were issued at the prevailing market price, as defined under the DRIP, with no broker fees or commissions.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 33

DIRECTORS AND EXECUTIVE OFFICERS

The name and municipality of residence, positions held and principal occupation of each Director of ARC Resources as at December 31, 2016 are set out below.

Directors
Name and Municipality of Residence	Director Since (1)	Principal Occupation During Past Five Years
Harold N. Kvisle Calgary, Alberta Canada	2009 (Chair)Independent	Mr. Kvisle is the Chairman of ARC’s Board, a position he has held since January 1, 2016. Prior to May 2015, he was President and Chief Executive Officer of Talisman Energy, and prior to September 2012, he was an independent business man.
David R. CollyerCalgary, Alberta Canada	2016Independent	Mr. Collyer is an independent businessman. Prior to 2014, Mr. Collyer was the President and Chief Executive Officer of the Canadian Association of Petroleum Producers.
John P. Dielwart Calgary, Alberta, Canada	1996Non-Independent	Mr. Dielwart is currently the Vice-Chairman of ARC Financial Corp, Canada’s largest energy focused private equity manager. Prior to January 2013, he was the Chief Executive Officer of ARC Resources.
Fred J. Dyment Calgary, Alberta, Canada	2003Independent	Mr. Dyment is an independent businessman.
Timothy J. Hearn Calgary, Alberta, Canada	2011Independent	Mr. Hearn is an independent businessman.
James C. Houck Calgary, Alberta, Canada	2008Independent	Mr. Houck is an independent businessman. Prior to August 2012, he was the President and Chief Executive Officer of the Churchill Corporation.
Kathleen M. O'Neill Toronto, Ontario, Canada	2009Independent	Ms. O’Neill is an independent businesswoman.
Herbert C. Pinder, Jr. Saskatoon, Saskatchewan, Canada	2006Independent	Mr. Pinder is an independent businessman.
William G. Sembo Calgary, Alberta, Canada	2013Independent	Mr. Sembo is an independent businessman. Prior to November 2013, he was the Vice Chairman and Managing Director at RBC Capital Markets LLC.
Nancy Smith Calgary, Alberta, Canada	2016Independent	Ms. Smith is a Director and Investment Committee Member of ARC Financial Corp, Canada’s largest energy focused private equity manager.
Myron M. Stadnyk Calgary, Alberta, Canada	2013 Management Director	Mr. Stadnyk is the President and Chief Executive Officer of ARC Resources. Prior to January 2013, he was the President and Chief Operating Officer of ARC Resources.

1) The term of each director is until the next annual meeting of ARC Resources, which is scheduled to be held on May 4, 2017.

All of the current Directors of ARC Resources were elected as Directors of ARC Resources Ltd. on April 21, 2016 to hold office until the next annual meeting of ARC Resources, with the exception of David R. Collyer who was appointed to the Board of Directors on November 10, 2016. The next annual meeting is scheduled to be held on May 4, 2017.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 34

As at December 31, 2016, the Directors and Officers of ARC Resources, as a group, beneficially owned, or controlled or directed, directly or indirectly, 4,301,836 Common Shares or approximately 1.2 per cent of the outstanding Common Shares.

The name and municipality of residence, position held and principal occupation during the past five years of each officer of ARC Resources as at December 31, 2016 are set out below.

Officers (1)(2)(3)
Name and Municipality of Residence	Office Held and Principal Occupation During Past Five Years
Myron M. Stadnyk Calgary, Alberta, Canada	President and Chief Executive OfficerMr. Stadnyk’s biographical information is included under “Directors”
P. Van R. Dafoe Calgary, Alberta, Canada	Senior Vice President and Chief Financial Officer Mr. Dafoe is the Senior Vice President and Chief Financial Officer of ARC Resources. Prior to February 2014, he was ARC’s Senior Vice President, Finance.
Terry M. Anderson Calgary, Alberta, Canada	Senior Vice President and Chief Operating Officer Mr. Anderson is the Senior Vice President and Chief Operating Officer of ARC Resources. Prior to January 2014, he was ARC’s Senior Vice President, Engineering.
Bevin M. Wirzba Calgary, Alberta, Canada	Senior Vice President, Business Development and Capital Markets Mr. Wirzba is the Senior Vice President, Business Development and Capital Markets of ARC Resources. Prior to January 2016, he was a Managing Director at RBC Dominion Securities.
Kristen J. Bibby Calgary, Alberta, Canada	Vice President, Finance Mr. Bibby is the Vice President, Finance of ARC Resources. Prior to August 2014, he was Vice President, Finance and Chief Financial Officer at Verano Energy Limited.
Sean R. A. Calder Calgary, Alberta, Canada	Vice President, Production Mr. Calder is the Vice President, Production of ARC Resources. Prior to September 2013, he was the Manager, Technical Operations North at ARC.
Larissa M. Conrad (4) Calgary, Alberta, Canada	Vice President, Engineering and Planning Ms. Conrad is the Vice President, Engineering of ARC Resources. Prior to February 2014, she was Manager Engineering South at ARC.
Neil A. Groeneveld (5) Calgary, Alberta, Canada	Vice President, Geosciences and Exploration Mr. Groeneveld was the Vice President Geosciences and Exploration of ARC Resources.
Wayne D. Lentz (6) Calgary, Alberta, Canada	Vice President, Business Analysis Mr. Lentz was the Vice President Strategy and Business Development at ARC Resources. Prior to December 2016, he was ARC’s the Vice President Strategy and Business Development.
Karen A. Nielsen (7) Calgary, Alberta, Canada	Vice President, Operations Ms. Nielsen is the Vice President, Operations of ARC Resources. Prior to August 2013, she was the Vice President, Engineering at Birchcliff Energy Ltd.
Lisa A. OlsenCalgary, Alberta, Canada	Vice President, Human ResourcesMs. Olsen is the Vice President, Human Resources of ARC Resources. Prior to January 2016, she was ARC’s Manager of Human Resources.
Grant A. Zawalsky (8) Calgary, Alberta, Canada	Managing PartnerMr. Zawalsky is the Managing Partner at Burnet, Duckworth & Palmer LLP (law firm)

ARC Resources Ltd. | 2016 | Annual Information Form | Page 35

1) Subsequent to 2016 year-end, Christopher D. Baldwin was promoted to the position of Vice President, Geosciences effective January 1, 2017.

2) Subsequent to 2016 year-end, Ryan V. Berrett was promoted to the position of Vice President, Marketing effective January 1, 2017

3) Subsequent to 2016 year-end, Armin Jahangiri was promoted to Vice President, Operations effective March 9, 2017.

4) Subsequent to 2016 year-end Larissa M. Conrad’s title changed to Vice President, Engineering and Planning.

5) As of December 31, 2016, Neil A. Groeneveld retired from ARC Resources.

6) Subsequent to 2016 year-end Wayne D. Lentz’s title changed to Vice President, Business Analysis

7) Subsequent to 2016 year-end, Karen A. Nielsen ceased to be an employee of ARC as of March 1, 2017.

8) Grant A. Zawalsky is not considered to be an “executive officer” of ARC as defined by NI 51-102 as he does not perform a policy-making function in respect of the Corporation.

MEMBERSHIP OF BOARD COMMITTEES

The following chart sets out the membership of the committees of the Board of Directors as at February 8, 2017.

Name of Director	Audit	Reserves	Risk	Human Resources & Compensation	Policy & Board Governance	Health, Safety & Environment
Non-Independent Directors
John P. Dielwart		√				Chair
Independent Directors
David R. Collyer			√			√
Fred J. Dyment			Chair		√
Timothy J. Hearn				Chair	√
James C. Houck	√	Chair
Harold N. Kvisle					√
Kathleen M. O'Neill	Chair	√
Herbert C. Pinder, Jr.				√	Chair
William G. Sembo				√		√
Nancy Smith	√		√

The Audit, Risk, Human Resources and Compensation and the Policy and Board Governance committees are entirely comprised of independent Directors. The Reserves and Health, Safety and Environment committees are comprised of a majority of independent Directors.

Mr. Dielwart, who is the Chair of the Health, Safety and Environment Committee and is a member of the Reserves Committee, retired from the position of CEO of ARC Resources effective January 1, 2013 but remains as a director. The Board of Directors has determined that Mr. Dielwart is not independent at this point in time. Mr. Stadnyk was promoted to the position of President and CEO of ARC Resources effective January 1, 2013 and was appointed as a director on such date. Mr. Stadnyk is considered to be a non-independent director.

OFFICER BIOGRAPHIES

The following comprises a brief description of the background of the current Officers of ARC Resources:

Myron M. Stadnyk, P. Eng.

Mr. Stadnyk is President and Chief Executive Officer of ARC Resources and has overall strategic and management responsibility for the Company. Mr. Stadnyk joined ARC in 1997, as the Company’s first operations employee, and in 2005 was appointed Senior Vice President, Operations and Chief Operating Officer. From 2009 to 2012, he held the position of President and Chief Operating Officer. Prior to joining ARC, Mr. Stadnyk worked with a major oil and gas company in both domestic and international operations. He holds a Bachelor of Science in Mechanical Engineering from the University of Saskatchewan and is a graduate of the Harvard Business School Advanced Management program. He is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA)

ARC Resources Ltd. | 2016 | Annual Information Form | Page 36

and currently serves as a Governor for the Canadian Association of Petroleum Producers. Mr. Stadnyk is also a member of the Board of Directors for STARS (Shock Trauma Air Rescue Society) Ambulance and the University of Saskatchewan Engineering Alumni Fund.

P. Van R. Dafoe, B. Comm., CPA, CMA

Mr. Dafoe is Senior Vice President and Chief Financial Officer of ARC Resources and oversees the finance, treasury, accounting, tax, risk management and information technology teams at ARC.  Prior to being appointed to the role of Senior Vice President and Chief Financial Officer in 2014, Mr. Dafoe was the Senior Vice President, Finance at ARC. Mr. Dafoe has 30 years of experience in the oil and gas industry and joined ARC in 1999 as Controller. He is a member of the Alberta Chartered Professional Accountants and has a Bachelor of Commerce (Honours) degree from the University of Manitoba. Mr. Dafoe obtained his Certified Management Accountant’s designation in 1995.

Terry M. Anderson, P. Eng.

Mr. Anderson is Senior Vice President and Chief Operating Officer of ARC Resources with responsibility for the execution of all aspects of ARC's operations and capital program.  He has over 20 years of operations and engineering experience. Prior to joining ARC in 2000, he worked at a major oil and gas company. Mr. Anderson holds a Bachelor of Science in Petroleum Engineering from the University of Wyoming. He is a member of the Association of Professional Engineers and Geoscientists of Alberta, Saskatchewan and British Columbia

Bevin M. Wirzba, P. Eng., MBA

Mr. Wirzba is Senior Vice President, Business Development and Capital Markets of ARC Resources and is responsible for ARC’s acquisition, disposition, land, business development and marketing activities and all facets of investor relations, communications and corporate governance. He has over 20 years of upstream and midstream technical and commercial experience including strategic advisory, investment analysis, project development, and merger, acquisition and divestiture evaluation and execution. Prior to joining ARC in 2016, Mr. Wirzba spent 10 years in the energy advisory and capital markets business of a global investment bank as a Managing Director. Prior thereto, he spent 12 years with a major multi-national corporation working in both North America and internationally. Mr. Wirzba holds a Bachelor of Science in Civil Engineering from the University of Alberta, has a Master in Business Administration from the Edinburgh Business School and is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).

Christopher (Chris) D. Baldwin, P. Geol.

Mr. Baldwin is Vice President, Geosciences of ARC Resources and is responsible for the execution of ARC’s geophysical and geological activities. Mr. Baldwin joined ARC in 2009 and has over 15 years of experience in oil and gas exploration, development, geology and geophysics. Prior to joining ARC, Mr. Baldwin held positions with large and intermediate oil and gas companies. Mr. Baldwin holds a Bachelor of Science in Geology from the University of Calgary and is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).

Ryan V. Berrett, B. MGMT, MBA

Mr. Berrett is Vice President, Marketing of ARC Resources and coordinates all marketing activities to ensure market access for ARC’s production. He has over 15 years of accounting, finance and marketing experience, having started his career at ARC in 2003. Mr. Berrett has led ARC’s marketing activities since 2010. Mr. Berrett holds a Bachelor of Management degree from the University of Lethbridge and an Executive MBA in Global Energy from the University of Calgary’s Haskayne School of Business.

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Kristen (Kris) J. Bibby, B. Comm., CPA, CA

Mr. Bibby is Vice President, Finance of ARC Resources and is responsible for ARC’s financial risk and research, treasury and information technology related activities.  He has over 18 years of experience in finance and accounting roles within the oil and gas industry. Prior to joining ARC in 2014, Mr. Bibby held the position as Chief Financial Officer at a junior oil and gas company with international operations.  He has a Bachelor of Commerce degree from the University of Saskatchewan, and is a member of the Alberta Chartered Professional Accountants.

Sean R. A. Calder, P.L. Eng.

Mr. Calder is Vice President, Production of ARC Resources, and manages all aspects of field production operations and health, safety and environment.  He has over 18 years of broad industry experience including, field operations, drilling and completions and facility management.  Mr. Calder joined ARC in 2005, and since this time has taken on roles of increasing responsibility. Prior to joining ARC, he worked at a major oil and gas company. Mr. Calder has a Bachelor of Applied Petroleum Engineering Technology degree from the Southern Alberta Institute of Technology (SAIT).  He is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA), as well as the Association of Science and Engineering Technology Professionals in Alberta (ASET).

Larissa (Lara) M. Conrad, P. Eng.

Ms. Conrad is Vice President, Engineering and Planning of ARC Resources with responsibility for all engineering and strategic planning activities.  She has over 18 years of experience in reservoir, exploration, development and production engineering, as well as government and regulatory relations. Ms. Conrad joined ARC in 2011, and since this time has taken on roles of increasing responsibility.  Prior to joining ARC, she worked at a major Canadian oil and gas producer.  Ms. Conrad has a Bachelor of Science degree in Mechanical Engineering from the University of Waterloo and is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).

Armin Jahangiri, P.Eng.

Armin is Vice President, Operations of ARC Resources and is responsible for overseeing the facilities, drilling and completions, health and safety, and the environment and regulatory teams. He has 20 years of extensive industry experience in operations and major project development and execution both in North America and internationally. Armin joined ARC in 2014, and since this time has taken on roles of increasing responsibility. Prior to joining ARC, he worked with a major Canadian oil and gas producer and a global oilfield services company. Armin holds a Bachelor of Science in Mechanical Engineering from the Shariff University of Technology, and a Master of Engineering in Reservoir Characterization from the University of Calgary. He is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).

Wayne D. Lentz, P. Eng.

Mr. Lentz is Vice President, Business Analysis of ARC Resources and is responsible for strategic planning and related activities. He brings over 25 years of experience in the oil and gas business covering production, engineering and operations. Prior to joining ARC in 1999, Mr. Lentz worked with a major exploration and production company in both domestic and international operations. He holds a Bachelor of Science in Petroleum Engineering from the University of Alberta. Mr. Lentz is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).

Lisa A. Olsen, BA

Ms. Olsen is Vice President, Human Resources of ARC Resources, and oversees ARC’s human resources, office services and records information management functions while supporting ARC’s high-performance culture. Ms. Olsen joined ARC in 2008 and has over 18 years of experience in Human Resources. Prior to joining ARC, Ms. Olsen spent over 10 years leading the human resources functions in both a Canadian oil & gas organization as well as for a major international consumer brand. Ms. Olsen has a Bachelor of Communications from Simon Fraser University and an HR Management Certificate from the BC Institute of Technology.

Grant A. Zawalsky, B. Comm, LL.B

Mr. Zawalsky acts as Corporate Secretary for ARC Resources. He is a managing partner at the law firm of Burnet, Duckworth & Palmer LLP, and has over 30 years of experience in securities and corporate law including securities offerings, mergers and acquisitions, and corporate governance. Mr. Zawalsky is currently a director for a number of public and private energy companies including, NuVista Energy, PrairieSky Royalty Ltd., Whitecap Resources and Zargon Oil and Gas.

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AUDIT COMMITTEE DISCLOSURES

National Instrument 52-110 (“NI 52-110”) relating to audit committees has mandated certain disclosures for inclusion in this Annual Information Form. The text of the Audit Committee's mandate is attached as Appendix D to this Annual Information Form.

MEMBERS OF THE AUDIT COMMITTEE

As of December 31, 2016, the members of the Audit Committee were Kathleen O'Neill (Chair), James C. Houck and Nancy Smith; each is independent and financially literate within the meaning of NI 52-110. The following comprises a brief summary of each member's education and experience:

Kathleen M. O'Neill

Ms. O’Neill is a Corporate Director and has extensive experience in accounting and financial services.  Previously, she was an Executive Vice-President of the Bank of Montreal (BMO) Financial Group with accountability for a number of major business units. Prior to joining BMO Financial Group in 1994, she was a partner with PricewaterhouseCoopers. Ms. O'Neill is an FCPA, FCA (Fellow of Institute of Chartered Accountants) and has an ICD.D designation from the Institute of Corporate Directors. Ms. O'Neill was a member of the Steering Committee on Enhancing Audit Quality sponsored by the CPA (Chartered Professional Accountants of Canada) and the Canadian Public Accountability Board. Ms. O’Neill is the past Chair of St. Joseph’s Health Centre and St. Joseph’s Health Center Foundation of Toronto. For the past three consecutive years, Ms. O’Neill has been awarded as one of Canada's Most Powerful Women by the Women's Executive Network.

James C. Houck

Mr. Houck has over 35 years of diversified experience in the oil and gas industry. Most recently, he held the position as President and Chief Executive Officer of the Churchill Corporation, a construction and industrial services company.  Previously he was President and Chief Executive Officer of Western Oil Sands. The greater part of his career was spent with ChevronTexaco Inc., where he held a number of senior management and officer positions, including President, Worldwide Power and Gasification Inc., and Vice President and General Manager, Alternate Energy Department.  Earlier in his career, Mr. Houck held various positions of increasing responsibility in Texaco’s conventional oil and gas operations.  Mr. Houck has a Bachelor of Engineering Science from Trinity University in San Antonio and a Master in Business Administration from the University of Houston.

Nancy L. Smith

Ms. Smith is a Director of ARC Financial Corp., Canada’s largest energy focused private equity manager.  Prior to joining ARC Financial in 1999, she held executive positions in finance and upstream marketing at a Canadian integrated energy company and spent the first five years of her career in corporate banking. Ms. Smith received a Master of Business Administration and a Bachelor of Arts (Economics) from the University of Alberta and has an ICD.D designation from the Institute of Corporate Directors.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The Audit Committee has not adopted specific policies and procedures for the engagement of non-audit services and pre-approves each such engagement or type of engagement for every fiscal year.

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Deloitte LLP acted as ARC's external auditor for the fiscal years ended December 31, 2015 and December 31, 2016. The following is a summary of the external audit and non-audit services fees by category.

Summary of External Audit and Non-Audit Service Fees	2015		2016
Audit Fees	$	872,585	$	694,430
Audit Related Fees (1)	$	70,727		-
Tax Fees (2)		-	$	14,499
All Other Fees (3)	$	18,781	$	17,452

1) The aggregate fees billed by our external auditor for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements but which are not included in audit services fees.

2) The aggregate fees billed by our external auditor for professional services for various tax advice.

3) The assessment fee billed by The Canadian Public Accountability Board per the National Instrument 52-108 Auditor Oversight mandate for reporting issuers to have an audit completed by a CPAB participant firm.

In keeping with ARC's commitment to best practices in corporate governance, ARC conducted a comprehensive review of its external auditors in 2015. Following the completion of the comprehensive review, in 2016, a tender process was completed for the selection of our auditor and the Board of Directors (on the recommendation of the Audit Committee) determined that PricewaterhouseCoopers LLP is to be appointed as ARC’s auditor for the 2017 fiscal year, subject to shareholder approval. Additional documents related to the change of auditor, being the Change of Auditor Notice and the acknowledgements of that notice by PricewaterhouseCoopers LLP and Deloitte LLP, can be found under the Corporation's profile on SEDAR. There were no “reportable events” within the meaning of NI 51-102.

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CONFLICTS OF INTEREST

The Board of Directors has adopted a Code of Business Conduct and Ethics and a Code of Ethics for Senior Financial Officers (the “Codes”). In general, the private investment activities of employees, Directors and Officers are not prohibited, however, should an existing investment pose a potential conflict of interest, the potential conflict is required by the Codes to be disclosed to the Chief Executive Officer, President or the Board of Directors. Any other activities of employees which pose a potential conflict of interest are also required by the Codes to be disclosed to the Chief Executive Officer, President or the Board of Directors. Any such potential conflicts of interests will be dealt with openly with full disclosure of the nature and extent of the potential conflicts of interests with the Corporation.

It is acknowledged in the Codes that employees, Officers and Directors may be Directors or Officers of other entities engaged in the oil and gas business, and that such entities may compete directly or indirectly with the Corporation. No assurance can be given that opportunities identified by Directors of ARC Resources will be provided to us. Passive investments in public or private entities of less than one per cent of the outstanding shares will not be viewed as “competing” with the Corporation. Any director, officer or employee of ARC Resources which is a director or officer of any entity engaged in the oil and gas business shall disclose such occurrence to the Board of Directors. Any director, officer or employee of ARC Resources who is actively engaged in the management of, or who owns an investment of one per cent or more of the outstanding shares, in public or private entities shall disclose such holding to the Board of Directors. In the event that any circumstance should arise as a result of such positions or investments being held or otherwise which in the opinion of the Board of Directors constitutes a conflict of interest which reasonably affects such person’s ability to act with a view to the best interests of the Corporation, the Board of Directors will take such actions as are reasonably required to resolve such matters with a view to the best interests of the Corporation. Such actions, without limitation, may include excluding such Directors, Officers or employees from certain information or activities of the Corporation.

The Business Corporations Act (Alberta) provides that in the event that an officer or director is a party to, or is a director or an officer of or has a material interest in any person who is a party to, a material contract or material transaction or proposed material contract or proposed material transaction, such officer or director shall disclose the nature and extent of his or her interest and shall refrain from voting to approve such contract or transaction.

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INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There is no material interest, direct or indirect, of any director or senior officer, or to our knowledge any person or company that is the direct or beneficial owner, or who exercises control or direction over more than 10 per cent of outstanding Common Shares, or any associate or affiliate of any of the foregoing, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to affect the Corporation.

DIVIDENDS AND DISTRIBUTIONS

DIVIDEND POLICY

The Board of Directors of ARC Resources has established a dividend policy of paying monthly dividends to holders of Common Shares, which will be paid to Shareholders of record on or about the 15^th day of each month. The payment of dividends by the Corporation commenced upon the Trust Conversion with a dividend declared to Shareholders of record on January 31, 2011 made payable on February 15, 2011. Prior to the Trust Conversion, ARC paid a regular distribution to holders of Trust Units since its inception in July of 1996.

It is expected that the dividends declared and paid will be “eligible dividends” for the purposes of the Tax Act, and thus qualify for the enhanced gross-up and tax credit regime available to certain holders of Common Shares. However, no assurances can be given that all dividends will be designated as “eligible dividends” or qualify as “eligible dividends”.

Notwithstanding the foregoing, the amount of future cash dividends, if any, will be subject to the discretion of the Board of Directors of ARC Resources and may vary depending on a variety of factors and conditions existing from time-to-time, including fluctuations in commodity prices, production levels, capital expenditures, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of solvency tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends.

For information relating to risks relating to dividends, see “Risk Factors – Risk Relating to Our Business and Operations – Dividends”.

In certain circumstances, the payment of dividends may be restricted by our borrowing agreements. For more information see “Other Information Relating to Our Business – Borrowing”.

DIVIDEND HISTORY

The following per Common Share dividends were made in the last three completed financial years of ARC:

Dividends	2016		2015		2014
January	$	0.10	$	0.10	$	0.10
February	$	0.05	$	0.10	$	0.10
March	$	0.05	$	0.10	$	0.10
April	$	0.05	$	0.10	$	0.10
May	$	0.05	$	0.10	$	0.10
June	$	0.05	$	0.10	$	0.10
July	$	0.05	$	0.10	$	0.10
August	$	0.05	$	0.10	$	0.10
September	$	0.05	$	0.10	$	0.10
October	$	0.05	$	0.10	$	0.10
November	$	0.05	$	0.10	$	0.10
December	$	0.05	$	0.10	$	0.10
Total	$	0.65	$	1.20	$	1.20

In February 2016, ARC’s Board of Directors approved a monthly dividend of $0.05 per share, down from the prior monthly level of $0.10 per share, commencing with the February 2016 dividend, payable on March 15, 2016.

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MARKET FOR SECURITIES

The Common Shares commenced trading on the TSX on January 6, 2011 following the completion of the Trust Conversion. The trading symbol for the Common Shares is ARX.

The following table sets forth the high and low closing prices and the aggregate volume of trading in 2016 of the Common Shares on the TSX for the periods indicated (as quoted by Bloomberg):

Toronto Stock Exchange	High		Low		Volume
January		18.76		15.04		47,960,000
February		19.04		16.60		50,800,000
March		19.65		17.96		43,860,000
April		21.17		17.61		44,440,000
May		21.62		20.12		34,980,000
June		23.07		20.24		40,170,000
July		23.47		21.57		27,590,000
August		23.83		22.21		25,300,000
September		23.73		21.07		27,780,000
October		24.27		22.77		27,580,000
November		24.05		22.11		33,730,000
December		24.29		22.80		31,290,000

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INDUSTRY CONDITIONS

Companies operating in the oil and natural gas industry are subject to extensive regulation and control of operations (including land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government with respect to the pricing and taxation of oil and natural gas through agreements among the governments of Canada, Alberta and British Columbia, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these regulations or controls will affect the Corporation's operations in a manner materially different than they will affect other oil and natural gas companies of similar size. All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments governments may enact in the future. The following outlines some of the principal aspects of legislation, regulations and agreements governing ARC’s operations.

PRICING AND MARKETING

Oil

In Canada, producers of oil are entitled to negotiate sales contracts directly with oil purchasers, which results in the market determining the price of oil. Worldwide supply and demand factors primarily determine oil prices; however, prices are also influenced by regional market and transportation issues. The specific price depends in part on oil quality, prices of competing fuels, distance to market, and availability of transportation, value of refined products, the supply/demand balance and contractual terms of sale. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB. The NEB underwent a consultation process to update the regulations governing the issuance of export licences. The updating process was necessary to meet the criteria set out in the federal Jobs, Growth and Long-term Prosperity Act (Canada) (the “Prosperity Act”) which received Royal Assent on June 29, 2012. The Regulations Amending the National Energy Board Act Part VI (Oil and Gas) Regulations came into effect on July 31, 2015 and provides the requirements for obtaining long-term licenses.

Natural Gas

Canada's natural gas market has been deregulated since 1985. Supply and demand determine the price of natural gas and price is calculated at the sales point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system, at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short-term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange, Intercontinental Exchange or the New York Mercantile Exchange in the United States, spot and future prices can also be influenced by supply and demand fundamentals on these platforms. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m³ per day) must be made pursuant to an NEB order. Natural gas export contracts of a longer duration (to a maximum of 40 years) or that deal with larger quantities, requires an exporter to obtain an export licence from the NEB.

THE NORTH AMERICAN FREE TRADE AGREEMENT

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the United States and Mexico came into force on January 1, 1994. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply.

All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited

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from imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports. NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The new administration in the United States has indicated an intention to seek renegotiation of NAFTA, the impact of which on the oil and gas industry is uncertain.

ROYALTIES AND INCENTIVES

General

Each province has legislation and regulations that govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined through negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by government regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced.  The majority of ARC’s assets are on Crown lands.

Occasionally, the governments of the Western Canadian provinces create incentive programs, often during periods of low commodity prices or to incent development of specific resources or specific technologies. Such programs can provide royalty rate reductions, royalty holidays or royalty tax credits to encourage exploration and development activity.

The following is a description of key royalty programs in the jurisdictions in which ARC operates. This is not meant to be a fulsome description of all royalty programs; please refer to the respective Province’s websites for full royalty details.

Alberta

On January 29, 2016, the Government of Alberta released and accepted the Royalty Review Advisory Panel's recommendations, which outlined the implementation of a “Modernized Royalty Framework” for Alberta (the “MRF”). The MRF took effect on January 1, 2017. Wells drilled prior to January 1, 2017 continue to be governed by the prior “Alberta Royalty Framework” (the “ARF”) for a period of 10 years, until January 1, 2027. The MRF is structured in three phases: (i) Pre-Payout, (ii) Mid-Life, and (iii) Mature. During the Pre-Payout phase, a fixed five per cent royalty applies until the well reaches payout. Well payout occurs when the cumulative revenue from a well is equal to the Drilling and Completion Cost Allowance (determined by a formula that approximates drilling and completion costs for wells based on depth, length and historical costs). The new royalty rate will be payable on gross revenue generated from all production streams (oil, gas, and natural gas liquids), eliminating the need to label a well as “oil” or “gas”. Post-payout, the Mid-Life phase will apply a higher royalty rate than the Pre-Payout phase. In the Mature phase, once a well reaches the tail end of its cycle and production falls below a Maturity Threshold, the royalty rate will move to a sliding scale (based on volume and price) with a minimum gross royalty rate of five per cent. The downward adjustment of the royalty rate in the mature phase is intended to account for the higher per-unit fixed cost involved in operating an older well.

Alberta Royalty Regimes Summary
Royalty Regime	Product	Incentive Period	Post Incentive or Mid-Lid (MRF)	Mature Phase
ARF – Royalty formulas base on price and production	Oil	5%	0% to 40%
	Gas		5% to 36%
	Liquids – C3 & C4 / C5+		Flat 30% / Flat 40%
MRF – Royalty formulas based on price with a reduction for lower production during the mature phase	Oil / Cond / C5+	Pre-payout 5%	10% to 40%	Minimum 5%
	Gas		5% to 36%
	C3 /C4		10% to 36%

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British Columbia

The amount payable for oil royalties depends on the type and vintage of the oil, the quantity of oil produced in a month, the value of that oil and any applicable royalty exemptions. ARC’s oil wells qualify for the lowest vintage royalty rates available reflecting the higher unit costs of both exploration and extraction.

The royalty payable on natural gas produced on Crown lands is determined by a sliding scale formula based on a reference price, which is the greater of the average net price obtained by the producer and a prescribed minimum price. For gas wells, the royalty rate depends on the date of acquisition of the tenure rights and the spud date of the well. Royalties on natural gas liquids are levied at a flat rate of 20 per cent of the sales volume.

British Columbia maintains a number of targeted royalty programs for key resource areas intended to increase the competitiveness of British Columbia's natural gas wells. Important programs applicable to our key properties are:

· Deep Well Royalty Credit Program, which provides a royalty credit for natural gas wells defined in terms of a dollar amount applied against royalties, and is well specific based on drilling and completion depths.

· The Government of British Columbia also maintains an Infrastructure Royalty Credit Program that provides royalty credits for up to 50 per cent of the cost of certain approved road construction or pipeline infrastructure projects intended to facilitate increased oil and gas exploration and production in under-developed areas and to extend the drilling season.

LAND TENURE

The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western provinces. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Each of the provinces of Alberta and British Columbia have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or license. The Government of British Columbia expanded its policy of deep rights reversion for leases issued after March 29, 2007 to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of the primary term.

Alberta also has a policy of “shallow rights reversion” which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licenses issued after January 1, 2009 at the conclusion of the primary term of the lease or license.

PRODUCTION AND OPERATION REGULATIONS

The oil and natural gas industry in Canada is highly regulated and subject to significant control by provincial regulators. Regulatory approval is required for, among other things, the drilling of oil and natural gas wells, construction and operation of facilities, the storage, injection and disposal of substances and the abandonment and reclamation of well-sites. In order to conduct oil and gas operations and remain in good standing with the applicable provincial regulator, ARC must comply with applicable legislation, regulations, orders, directives and other directions (all of which are subject to governmental oversight, review and revision, from time to time). Compliance with such legislation, regulations, orders, directives or other directions can be costly and a breach of the same may result in fines or other sanctions.

ENVIRONMENTAL REGULATION

The oil and natural gas industry is subject to environmental regulation under a variety of Canadian federal, provincial, territorial and municipal laws and regulations, all of which are subject to governmental review and revision from time-to-time. Such legislation provides for, among other things, restrictions and prohibitions on the spill, release or

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emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability and the imposition of material fines and penalties. In addition to these specific, known requirements, future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gas (“GHG”) emissions, may impose further requirements on operators and other companies in the oil and natural gas industry.

Federal

Canadian environmental regulation is the responsibility of the federal government and provincial governments. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law will prevail, however, such conflicts are uncommon. The federal government has primary jurisdiction over federal works, undertakings and federally regulated industries such as railways, aviation and interprovincial transport. The Canadian Environmental Protection Act, 1999 and the Canadian Environmental Assessment Act, 2012 provide the foundation for the federal government to protect the environment and cooperate with provinces to do the same.

Pursuant to the Prosperity Act, the Government of Canada amended or repealed several pieces of federal environmental legislation and in addition, created a new federal environmental assessment regime that came in to force on July 6, 2012. The changes to the environmental legislation under the Prosperity Act are intended to provide for more efficient and timely environmental assessments of projects that previously had been subject to overlapping legislative jurisdiction.

On June 20, 2016, the Federal Government launched a review of current environmental and regulatory processes with a focus on rebuilding trust in the environmental assessment processes, modernizing the NEB, and introducing modernized safeguards to both the Fisheries Act and the Navigation Protection Act. An Expert Panel has been convened and is expected to complete its work by May 15, 2017. At such time, the Minister of Environment and Climate Change will consider the recommendations in the Panel’s report and identify next steps to improve federal environmentalprocesses, which is expected to take place during the summer/fall of 2017. Until this process is complete, the Federal Government's interim principles released January 27, 2016 will continue to guide decision-making authorities for projects currently undergoing environmental assessment. The Federal Government has not provided any indication on what changes—if any—will be implemented or when, but increased delays and uncertainty surrounding the environmental assessment process should be expected for large projects.

In a further development, on November 29, 2016, the Government of Canada announced that it would introduce legislation by spring 2017 to formalize a moratorium for crude oil tankers on British Columbia's north coast. It is unclear how the proposed moratorium may affect ongoing LNG export projects currently under consideration and development. On the same day, the Government of Canada also approved, subject to a number of conditions, the Trans Mountain Pipeline system expansion backed by Kinder Morgan Canada as well as the replacement of Enbridge Inc.'s plan to replace its Line 3 pipeline system, while also rejecting Enbridge Inc.'s proposed Northern Gateway project.  On January 11, 2017, the Government of British Columbia confirmed that the conditions to the approval of the Trans Mountain Pipeline have been satisfied. Additionally, the new administration in the United States has indicated a willingness to revisit other pipeline projects that had been previously rejected.

Alberta

The Alberta Energy Regulator (the “AER”) is the single regulator responsible for all energy development in Alberta. The AER ensures the safe, efficient, orderly, and environmentally responsible development of hydrocarbon resources including allocating and conserving water resources, managing public lands, and protecting the environment. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as Alberta Energy's responsibility for mineral tenure. The objective behind a single regulator is an enhanced regulatory regime that is efficient, attractive to business and investors, and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners.

The Government of Alberta relies on regional planning to accomplish its responsible resource development goals. The following frameworks, plans and policies form the basis of Alberta's Integrated Resource Management System (“IRMS”). The IRMS method to natural resource management provides for engagement and consultation with stakeholders and the publicand examines the cumulative impacts of development on the environment and communities, by incorporating the management of all resources, including energy, minerals, land, air, water and biodiversity. While the AER is the primary regulator for energy development, several other governmental departments

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and agencies may be involved in land use issues, including Alberta Environment and Parks, Alberta Energy, the Policy Management Office, the Aboriginal Consultation Office and the Land Use Secretariat.

In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the “ALUF”). The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.

Proclaimed in force in Alberta on October 1, 2009, the Alberta Land Stewardship Act (the “ALSA”) provides the legislative authority for the Government of Alberta to implement the policies contained in the ALUF. Regional plans established under the ALSA are deemed to be legislative instruments equivalent to regulations and will be binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licenses, registrations, approvals and authorizations for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan. Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment.

In July 2014, the Government of Alberta approved the South Saskatchewan Regional Plan (“SSRP”) which came into force on September 1, 2014. The SSRP is the second regional plan developed under the ALUF. The SSRP covers approximately 83,764 square kilometres and includes 44 per cent of the provincial population. The SSRP creates four new and four expanded conservation areas, and two new and six expanded provincial parks and recreational areas. The SSRP will honour existing petroleum and natural gas tenure in conservation and provincial recreational areas. However, any new petroleum and natural gas tenures sold in conservation areas, provincial parks, and recreational areas will prohibit surface access. However, oil and gas companies must minimize impacts of activities on the natural landscape, historic resources, wildlife, fish and vegetation when exploring, developing and extracting the resources. Freehold mineral rights will not be subject to this restriction.

British Columbia

In British Columbia, the Oil and Gas Activities Act (the “OGAA”) impacts conventional oil and gas producers, shale gas producers and other operators of oil and gas facilities in the province. Under the OGAA, the British Columbia Oil and Gas Commission (the “Commission”) has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for oil and gas activities. The Environmental Protection and Management Regulation establishes the government's environmental objectives for water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the Commission to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity. In addition, although not an exclusively environmental statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires proponents to obtain various approvals before undertaking exploration or production work, such as geophysical licenses, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to environmental considerations and licenses and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.

LIABILITY MANAGEMENT RATING PROGRAMS

The provinces of Alberta and British Columbia have each implemented similar liability management programs in respect to upstream oil and gas wells, facilities and pipelines. These programs are designed to assess a licensee’s ability to address its suspension, abandonment, remediation and reclamation liabilities. A licensee whose deemed liabilities exceed its deemed assets within the jurisdiction are required to provide a security deposit.

On June 20, 2016, the AER issued Bulletin 2016-16, Licensee Eligibility—Alberta Energy Regulator Measures to Limit Environmental Impacts Pending Regulatory Changes to Address the Redwater Decision ("Bulletin 16") in an urgent response to a decision from the Alberta Court of Queen's Bench, which is currently under appeal with the

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Court of Appeal of Alberta. In Redwater Energy Corporation (Re), 2016 ABQB 278 ("Redwater"), Chief Justice Wittman found that there was an operational conflict of law between the abandonment and reclamation provisions of the provincial OGCA and the ability to disclaim assets under the federal Bankruptcy and Insolvency Act ("BIA"). Chief Justice Wittman’s decision renders the AER's legislated authority under the OGCA unenforceable such that the AER cannot impose abandonment orders against licensees or require a licensee to pay a security deposit before approving a transfer when such a licensee is insolvent. Effectively, this means that abandonment costs will be borne by the industry-funded Orphan Well Fund or the province in these instances because any resources of the insolvent licensee will first be used to satisfy secured creditors under the BIA. The purpose of Bulletin 16 is to provide interim rules to govern while the case is appealed and while the Government of Alberta develops appropriate regulatory measures to adequately address environmental liabilities. Three changes were implemented to minimize the risk to Albertans:

1. The AER will consider and process all applications for licence eligibility under Directive 067: Applying for Approval to Hold EUB Licences as non-routine and may exercise its discretion to refuse an application or impose terms and conditions on a licencee eligibility approval if appropriate in the circumstances.

2. For holders of existing but previously unused licence eligibility approvals, prior to approval of any application (including licence transfer applications), the AER may require evidence that there have been no material changes since approving the licence eligibility. This may include evidence that the holder continues to maintain adequate insurance and that the Directors, Officers, and/or Shareholders are substantially the same as when licence eligibility was originally granted.

3. As a condition of transferring existing AER licences, approvals, and permits, the AER will require all transferees to demonstrate that they have a liabilitymanagement rating ("LMR"), being the ratio of a licensee's assets to liabilities, of 2.0 or higher immediately following the transfer.

In order to clarify and revise the interim rules in Bulletin 16, the AER issued Bulletin 2016-21: Revision and Clarification on Alberta Energy Regulator’s Measures to Limit Environmental Impacts Pending Regulatory Changes to Address the Redwater Decision ("Bulletin 21") on July 8, 2016 and reaffirmed its position that an LMR of 1.0 is not sufficient to ensure that licensees will be able to address their obligations throughout the life cycle of energy development, and 2.0 remains the requirement for transferees. However, Bulletin 21 did provide the AER with additional flexibility to permit licensees to acquire additional AER-licensed assets if:

1. The licensee already has an LMR of 2.0 or higher;

2. The acquisition will improve the licensee's LMR to 2.0 or higher; or

3. The licensee is able to satisfy its obligations, notwithstanding an LMR below 2.0, by other means.

The AER provided no indication of what other means would be considered. In the short term these temporary measures have delayed the closing of transactions, have deterred parties from transacting   and have reduced the pool of possible purchasers.  However, the AER has exercised its discretion resulting in some transactions being approved following a more rigorous review by the AER, despite a transferee's LMR not meeting the temporary requirement. The Alberta Court of Appeal heard the appeal of the Redwater decision on October 11, 2016, with the Court reserving its decision.

CLIMATE CHANGE REGULATION

ARC operates in jurisdictions that have regulated or have proposed to regulate greenhouse gas (“GHG”) emissions and other air pollutants. While some regulations are in effect, others are at various stages of review, discussion and implementation. There is uncertainty around how any future federal legislation will harmonize with provincial regulation, as well as the timing and effects of regulations. Climate change regulation at both the federal and provincial level has the potential to significantly affect the regulatory environment of the oil and natural gas industry in Canada. Such regulations, surveyed below, impose certain costs and risks on the industry. In general, there is some uncertainty with regard to the impacts of federal or provincial climate change and environmental laws and regulations, as it is currently not possible to predict the extent of future requirements. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on the Corporation's operations and cash flow.

Federal

The United Nations Framework Convention on Climate Change, held in Paris, France in December 2015, brought together 196 Nations and resulted in the Paris Agreement, which came into effect November 4, 2016. Among other items, the Paris Agreement constitutes the actions and targets that individual countries will undertake to help keep global temperatures from rising more than 2° Celsius and to pursue efforts to limit below 1.5° Celsius. The

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Government of Canada ratified the Paris Agreement on December 12, 2016, and pursuant to the agreement, set forth Nationally Determined Contributions (“NDC”) of 30 per cent reduction below 2005 levels by 2030.

On June 29, 2016, the North American Climate, Clean Energy and Environment Partnership was announced among Canada, Mexico and the United States, which announcement included an action plan for achieving a competitive, low-carbon and sustainable North American economy. The plan includes setting targets for clean power generation, committing to implement the Paris Agreement, setting out specific commitments to address certain short-lived climate pollutants, and the promotion of clean and efficient transportation.

The Government of Canada formally announced the Pan-Canadian Framework on Clean Growth and Climate Change on December 9, 2016. As a result, the federal government will implement a Canada-wide carbon pricing scheme beginning in 2018. This may be implemented through either a cap and trade system or a carbon tax regime at the option of each province or territory. The federal government will impose a price on carbon of $10 per tonne on any province or territory which fails to implement its own system by 2018. This amount will increase by $10 annually until it reaches $50 per tonne in 2022 at which time the program will be reviewed.

Alberta

Following the Climate Advisory Panel's Climate Leadership report, the Government of Alberta announced its Climate Leadership Plan in November 2015. In June, 2016, the Government of Alberta passed into law the Climate Leadership Implementation Act (“CLIA”). The CLIA enacted the Climate Leadership Act (“CLA”) introducing a carbon tax on all sources of GHG emissions, subject to certain exemptions. An initial economy-wide levy of $20 per tonne was implemented on January 1, 2017, increasing to $30 per tonne in January of 2018. All fuel consumption, including gasoline and natural gas, will be subject to the levy, with certain exemptions, and Directors of a corporation may be held jointly and severally liable with a corporation when the corporation fails to remit an owed carbon levy. Natural gas produced and consumed on site by conventional oil and gas producers will be exempt from the carbon levy until January 1, 2023.

The Government of Alberta renewed the Specified Gas Emitters Regulation (“SGER”) enacted under the Climate Change and Emissions Management Act (Alberta), on June 25, 2015, for a period of two years with significant amendments while Alberta's newly formed Climate Advisory Panel conducted a comprehensive review of the province's climate change policy. Amendments have increased the minimum emission intensity reduction requirements for regulated facilities to a 15 per cent reduction from its baseline in 2016 and to a 20 per cent reduction in 2017. Regulated Emitters will remain subject to the SGER framework until the end of 2017; upon the expiry of the SGER, the Government of Alberta intends to transition to a proposed Carbon Competitiveness Regulation, in which sector specific output-based carbon allocations will be used to ensure competitiveness. A 100 megatonne per year limit for GHG emissions was implemented for oil sands operations, which currently emit roughly 70 megatonnes per year. This cap makes provisions for new upgrading and cogeneration facilities, which are allocated a separate 10 megatonne limit. Regulations accompanying the CLIA have not yet been released. All of ARC’s facilities in Alberta are currently under emissions thresholds.

The passing of the CLIA is the first step towards executing the Climate Leadership Plan (other legislation is still pending). In addition to enacting the CLA, the CLIA also enacted the Energy Efficiency Alberta Act, which enables the creation of Energy Efficiency Alberta, a new Crown corporation to support and promote energy efficiency programs and services for homes and businesses.

British Columbia

British Columbia enacted a carbon tax in February 2008, which is currently capped at $30 per tonne of CO2 through to 2018. The carbon tax is revenue neutral, wherein the Government of British Columbia has implemented tax credits and reductions in order to offset the tax revenues that the Government of British Columbia would otherwise receive from the tax.

British Columbia is a member of the Western Climate Initiative (“WCI”), a multi-jurisdictional partnership created in 2007 to address climate change by supporting the implementation of state and provincial greenhouse gas emission trading programs. In April, 2008, the Government of British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act (the “Cap and Trade Act”), which received royal assent on May 29, 2008 and partially came into force by regulation of the Lieutenant Governor in Council. It sets a province-wide target of a 33% reduction in the 2007 level of GHG emissions by 2020 and an 80% reduction by 2050. Unlike the emissions intensity approach taken

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by the federal government and the Alberta government, the Cap and Trade Act establishes an absolute cap on GHG emissions.

The Greenhouse Gas Emission Reporting Regulation, implemented under the authority of the Cap and Trade Act, set out the requirements for the reporting of the GHG emissions from facilities in British Columbia emitting 10,000 tonnes or more of carbon dioxide equivalent emissions per year beginning on January 1, 2010. Those reporting operations with emissions of 25,000 tonnes or greater are required to have emissions reports verified by a third party. The reporting system for large emitters of GHGs has since been streamlined by the Greenhouse Gas Industrial Reporting and Control Act (the “GGIRCA”) and its associated regulations that came into force on January 1, 2016. The GGIRCA sets out benchmarked performance standards for different industrial facilities and sectors, provides for emissions offsets through the purchase of emission credits or emission offsetting projects, among other measures, and replaces the Cap and Trade Act. ARC’s gas plants and field operations in British Columbia are subject to provincial reporting regulation.

On August 19, 2016, the Government of British Columbia unveiled its Climate Leadership Plan with a goal to reduce net annual GHG emissions by up to 25 million tonnes below current forecasts by 2050, and reaffirmed that it will achieve its 2050 target of an 80% reduction in emissions from 2007 levels. In addition to various measures across the economy that are designed to incentivize the growth of the renewable energy sector, the use of low GHG emitting technologies, and the improvement of energy efficiency, among other goals, the Government of British Columbia will soon implement a formal policy to regulate carbon capture and storage projects. Further, the Climate Leadership Plan sets out a strategy to reduce methane emissions in the upstream natural gas sector, beginning with a Legacy phase that targets a 45% reduction in fugitive and vented emissions by 2025 for facilities built before January 1, 2015, followed by a Transition phase for facilities built between 2015 and 2018 that involves a new offset protocol and a Clean Infrastructure Royalty Credit Program along with other incentives, and finally a Future phase that will implement standards going forward.

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RISK FACTORS

Investors should carefully consider the risk factors set out below and consider all other information contained herein and in the Corporation's other public filings before making an investment decision. The risks set out below are not an exhaustive list and should not be taken as a complete summary or description of all the risks associated with the Corporation's business and the oil and natural gas business generally.

Residents of the United States and other non-residents of Canada should have additional regard to the risk factors under the heading “Risk Factors Applicable to Residents of the United States and Other Non‑Residents of Canada”.

RISKS RELATING TO OUR BUSINESS AND OPERATIONS

Volatility of Commodity Prices

Our operational and financial results are dependent on the prices received for oil and natural gas production. Oil and natural gas prices respond to supply/demand imbalances and are volatile.

Oil and natural gas prices are determined by supply and demand and in the case of oil prices, political factors and a variety of additional factors beyond our control. These factors include but are not limited to economic conditions, both in North America and worldwide, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability, the increased capacity to bring new production on stream due to technology such as multi-stage fracturing, the foreign supply of oil and natural gas, supply disruption, transportation disruption, the price of foreign imports and the availability of alternative fuel sources and changing demand for petroleum products. North America has an abundance of oil and natural gas reserves, primarily as a result of advancements in hydraulic fracturing techniques. Natural gas prices are impacted by weather, North American inventory levels, and other factors.

Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the carrying value of our proved and probable reserves, net asset value, borrowing capacity, production, revenues, profitability and funds from operations, levels of capital expenditures and ultimately on our financial condition and therefore on the dividends to be paid to our Shareholders.

Government Regulation

Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration, development, production, pricing, marketing and transportation). Governments may regulate or intervene with respect to exploration and production activities, prices, taxes, royalties and the exportation of oil and natural gas. Amendments to these controls and regulations may occur from time to time in response to economic or political conditions. Many of these controls and regulations are subject to exercise of political, governmental and judicial discretion, which may be exercised in a manner that may negatively impact our business. See “Industry Conditions”. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase our costs, either of which may have a material adverse effect on our business, financial condition, results of operations and prospects. In order to conduct oil and natural gas operations, we will require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities at the provincial and federal level. There can be no assurance that we will be able to obtain all of the permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that we may wish to undertake. In addition, certain federal legislation such as the Competition Act and the Investment Canada Act could negatively affect our business, financial condition and the market value of our Common Shares or assets, particularly when undertaking, or attempting to undertake, acquisition or disposition activity.

Market Access Constraints and Transportation Interruptions

We deliver our products through gathering, processing and pipeline systems (some of which we do not own). The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of these systems. This access to market affects regional price differentials, which could result in the inability to realize the full economic potential of our production. Although the transportation systems are expanding, the lack of firm transportation capacity continues to affect the industry and has the potential to limit the ability to produce and to market our production. North America has an integrated network of natural gas pipelines however regional restrictions can arise resulting in curtailments. Any significant change in market factors, infrastructure regulation or

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other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm our business and, in turn, our financial condition, results of operations and funds from operations.

ARC has entered into certain long-term take-or-pay transportation commitments to deliver products through third-party owned infrastructure which creates a financial liability and there can be no assurance that future volume commitments will be met which may adversely affect our income and funds from operations. For more information regarding these long-term transportation commitments, see Note 20 “Commitments and Contingencies” in ARC’s Audited Consolidated Financial Statements as at and for the year ended December 31, 2016 which section is incorporated in this Annual Information Form by reference and is found on our SEDAR profile at www.sedar.com.

A portion of our production is processed through facilities owned by third parties, which we do not control. From time-to-time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuance or decrease of operations could adversely affect our ability to process our production and to deliver the same for sale.

Public Perception and Influence on Regulatory Regime

Concern over the impact of oil and gas development on the environment and climate change has received considerable attention in the media and recent public commentary, and the social value proposition of resource development is being challenged.  Additionally, certain pipeline leaks, and induced seismicity events have gained media, environmental and other stakeholder attention. Future laws and regulation may be impacted by such incidents, which could impede the conduct of our business or make our operations more expensive.

Environmental Regulation

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with oil and gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites.

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge. Although ARC believes that it will be in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, transportation and processing, financial condition, results of operations and prospects.

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Climate Change

ARC’s exploration and production facilities and other operations and activities emit greenhouse gases which may require it to comply with GHG emissions legislation at the provincial or federal level. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. The direct or indirect costs of compliance with these regulations may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. Some of ARC’s significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation and development of fossil fuels. Given the evolving nature of the debate related to climate change and the control of GHG and resulting requirements, it is not possible to predict the impact on the Corporation and its operations and financial condition. See “Industry Conditions - Climate Change Regulation”.

Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial quantities of oil and natural gas from reservoirs that were previously unproductive. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase our costs of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from its reserves.

Global Economic Events

Market events and conditions, including disruptions in the international credit markets and other financial systems and the American and European sovereign debt levels, may cause significant volatility to commodity prices and a decline in funds from operations. Global economic events and conditions may cause a loss of confidence in the broader global credit and financial markets and create a climate of greater volatility, less liquidity, wider credit spreads, a lack of price transparency and increased credit losses. Market events in the future may affect our ability to obtain equity or debt financing on acceptable terms and may make it more difficult to operate effectively.

Royalty Regimes

There can be no assurance that the federal government and the provincial governments of the western provinces will not adopt new royalty regimes or modify the existing royalty regimes which may have an impact on the economics of our projects. An increase in royalties would reduce our earnings and could make future capital investments, or our operations, less economic. On January 29, 2016, the Government of Alberta adopted a new royalty regime which took effect on January 1, 2017. See “Industry Conditions - Royalties and Incentives”.

Foreign Exchange Rates Fluctuations

Fluctuations in foreign exchange rates of the Canadian dollar relative to the U.S. dollar may affect ARC’s revenue as global oil prices and natural gas liquids, and Canadian natural gas exports to the U.S. are denominated in U.S. dollars. A decrease in the value of the U.S. dollar relative to the Canadian dollar may reduce the price received by ARC for its products in Canadian dollar terms. In addition, ARC holds a significant portion of its debt denominated in U.S. dollars. Since ARC reports in Canadian dollars, U.S. dollar debt is translated to a Canadian dollar equivalent and therefore its reported level of indebtedness is affected by the foreign exchange rate between the U.S. dollar and Canadian dollar. An increase in the U.S. dollar relative to the Canadian dollar will increase the reported value of debt and interest payments, as expressed in Canadian dollars.

Interest Rate Risk

There is a risk that interest rates will increase. Current interest rates are low compared to historical levels. An increase in interest rates may result in an increase in the amount we pay to service debt, resulting in a decrease in funds from operations. This could affect dividends to Shareholders and the market price of the Common Shares. Further, the value of our Common Shares may decline in an environment of increasing interest rates as investors’ rate of return expectations may be higher.

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Exploration, Development and Production Risks

Acquiring, developing and exploring for oil and natural gas involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. These risks include, but are not limited to, encountering unexpected formations or pressures, premature declines of reservoirs, uncontrollable flow of hydrocarbons, equipment failures and other accidents, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires, spills and delays in payments between parties caused by operation or economic matters. These risks will increase as we undertake more exploratory activity. Drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. Although we maintain insurance in accordance with customary industry practice, we are not fully insured against all of these risks. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on our business, financial condition, results of operations and prospects.

Continuing production from a property, and to some extent the marketing of production, are largely dependent upon the ability of the operator of the property. Other companies operate some of the properties in which we have an interest and as a result our returns on assets operated by others depends upon a number of factors outside our control. To the extent the operator fails to perform these functions properly, operating income may be reduced.

Losses resulting from the occurrence of any of these risks may have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to maintain the payment of dividends.

Project Risks

We manage a variety of small and large projects in the conduct of our business. We have undertaken large development projects, including the construction of gas processing and liquids handling facilities, in northeastern British Columbia for the development of our natural gas and crude oil reserves. Project delays may impact expected revenues from operations. Significant project cost over‑runs could make a project uneconomic. Our ability to execute projects and market oil and natural gas depends upon numerous factors beyond our control, including:

· availability of processing capacity;

· availability and proximity of pipeline capacity;

· availability of storage capacity;

· supply of and demand for crude oil and natural gas;

· availability of alternative fuel sources;

· effects of inclement weather;

· availability of drilling and completions related equipment and resources;

· unexpected cost increases;

· accidental events;

· changes in regulations; and

· availability and productivity of skilled labour.

Because of these factors, we could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that we produce.

Reliance on Key Personnel

Our success depends in large measure on certain key personnel and our ability to hire and retain our key personnel, and the loss of our key personnel could delay the completion of certain projects or otherwise have a material adverse effect on us. Shareholders will be dependent on our management and staff in respect of the administration and management of all matters relating to our properties, and the safekeeping of our primary workspace and computer systems. Any deterioration of our corporate culture could adversely affect our long-term success.

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Dividends

The payment of dividends is at the discretion of the Board of Directors. Dividends on the Common Shares are not preferential, nor cumulative, nor stipulated by their terms to be at a fixed amount or rate. As such dividends do not represent a “yield” in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Dividends are conditionally declared by our Board in its sole discretion and are subject to confirmation by a monthly press release and are specifically subject to change in accordance with our dividend policy. The dividend policy is also subject to change in the sole discretion of our Board of Directors. See “Dividends and Distributions – Dividend Policy”. Dividends may be varied, suspended or discontinued at any time.

Our ability to add to our oil and natural gas reserves is highly dependent on our success in exploiting existing properties and acquiring additional reserves. The production from individual wells and properties declines over time. We currently distribute a portion of our funds from operations, by way of dividend payments, to Shareholders rather than reinvesting it in reserves additions. Our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves may be dependent on the level of our funds from operations and external sources of capital. There is no assurance we will be successful in developing additional reserves or acquiring additional reserves on terms that meet our investment objectives. Without these reserves additions, our reserves will deplete and as a consequence, either production from, or the average reserves life of, our properties will decline, which may result in a reduction in the value of Common Shares and in a reduction in funds from operations available for the payment of dividends to Shareholders.

Information Technology Systems

We are increasingly dependent upon the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure, to conduct daily operations. We depend on various information technology systems to estimate reserve quantities, process and record financial data, manage our land base, analyze seismic information, administer our contracts with our operators and lessees and communicate with employees and third-party partners.

Cyber-Security

We employ and depend upon information technology systems to conduct our business. These systems have the potential to introduce information security risks, which are growing in both complexity and frequency and could include potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of our information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to our business activities or our competitive position. Further, disruption of critical information technology services, or breaches of information security, could have a negative effect on our assets, performance and earnings, as well as on our reputation. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on ARC’s business, financial condition and results of operations.

Third Party Credit Risk

We are exposed to third-party credit risk through our contractual arrangements with our current or future joint venture partners, third party operators, purchasers of our petroleum and natural gas production, hedge counterparties and other parties. Poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of such program until we find a suitable alternative partner.

Industry Competition

There are numerous companies in the oil and gas industry, who are competing with us for the acquisition of properties and undeveloped land. As a result of such competition, it may be more difficult for us to acquire reserves on beneficial terms. A number of these other oil and gas companies have significantly greater financial and other resources than we do.

Oil and natural gas exploration and development activities are dependent on the availability of drilling, completions and related equipment (typically leased from third parties) in the particular areas where such activities will be

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conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities.

We compete with other oil and gas entities to hire and retain skilled personnel necessary for our daily operations including planning, realizing on available technical advances and the execution of the annual capital program. The inability to hire and retain skilled personnel could adversely impact certain of our operational and financial results.

Cost of New Technology

The oil and gas industry is characterized by rapid and significant technological advancements. Other companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before ARC. There can be no assurance that we will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. One or more of the technologies currently utilized by ARC or implemented in the future may become obsolete. In such case, our business, financial condition and results of operations could be adversely and materially affected. If we are unable to utilize the most advanced commercially available technology, our business, financial condition and results of operations could also be adversely affected in a material way.

Substantial Capital Requirements and External Sources of Capital, Borrowing and Equity

We anticipate making substantial capital expenditures for the development of oil and natural gas reserves in the future. Other capital expenditures may also include exploration, undeveloped land and acquisitions from time-to-time. Future capital expenditures will be financed out of funds from operations, borrowings, property dispositions and possible future equity issuances; however, our ability to do so is dependent on, among other factors, the overall state of capital markets and investor appetite for investments in the energy industry and our securities in particular. Further, if our revenues or reserves decline, we may not have access to the capital necessary to undertake or complete future capital expenditure programs.

Alternatively, we may issue additional Common Shares from treasury at prices which may result in a decline in production per Common Share and reserves per Common Share or we may wish to borrow to finance significant acquisitions or development projects to accomplish our long-term objectives on less than optimal terms or in excess of our optimal capital structure.

To the extent that external sources of capital become limited or unavailable or available on onerous terms, our ability to make capital investments and maintain or expand existing assets and reserves may be impaired, and our assets, liabilities, business, financial condition, results of operations and dividend payments may be materially and adversely affected as a result.

From time-to-time we may enter into transactions to acquire assets or shares of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms. The level of our indebtedness from time-to-time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise

Hedging Activities

We actively manage the risk associated with changes in commodity prices by entering into oil and natural gas price hedges. If we hedge our commodity price exposure, we will forego some of the benefits we would otherwise experience if commodity prices were to increase, and some of these foregone benefits may be material relative to funds from operations. For more information in relation to our commodity hedging program, see “Statement of Reserve Data and Other Oil and Gas Information – Forward Contracts”. We also may initiate certain hedges to attempt to mitigate the risk of the Canadian dollar fluctuating in relation to the U.S. dollar. These hedging activities could expose us to losses, which may be material, and to credit risk associated with counterparties with who we contract.

Credit Facility Arrangements

We have a Cdn$950 million syndicated credit facility with 11 banks, which was undrawn as at December 31, 2016. The current maturity date of the facility is November 6, 2020. The terms of the credit facility allow for annual renewals

ARC Resources Ltd. | 2016 | Annual Information Form | Page 57

at the request of ARC and at the discretion of the lenders. At December 31, 2016, ARC had US$734.4 million and Cdn$1,026.0 million of long-term debt outstanding in the form of Long-term Notes (“Notes”). The Notes are repayable over the next 10 years. We intend to fund these repayments with existing credit facilities and/or with proceeds from additional note issuances. Although we believe the credit facilities will be sufficient for our immediate requirements, there can be no assurance that the amount will be adequate for our future financial obligations including our future capital expenditure programs, that additional funds will be able to be obtained or that we will be able to extend or renew our credit facilities.

We are required to comply with covenants under the credit facility and under our Notes. In the event that we do not comply with covenants under the credit facility and our Notes, our access to capital could be restricted or repayment could be required on an accelerated basis by our lenders, and the ability to pay dividends to our Shareholders may be restricted.

Variations in interest rates and scheduled principal repayments could result in changes in the amount required to be applied to debt service resulting in a decrease in the amount available for payment of dividends on the Common Shares. Certain covenants of the agreements with our lenders may also limit the payment of dividends. For more information, see “Other Information Relating to Our Business – Borrowing”.

Liability Management Programs

Alberta and British Columbia have developed liability management programs designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder becomes defunct. These programs generally involve an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities exceed its deemed assets, a security deposit is required. Changes of the ratio of our deemed assets to deemed liabilities or changes to the requirements of liability management programs may result in significant increases to the security that must be posted. See “Industry Conditions – Liability Management Rating Programs”.

Reserve and Resources Estimates

There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves and resources including many factors beyond our control. In general, estimates of economically recoverable oil and natural gas reserves and resources, the future net revenues and finding and development costs are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results.

The reserves and recovery information and the resource information contained herein and in the GLJ Report are only estimates and the actual production and ultimate reserves and resources from the properties may be greater or less than such estimates prepared by GLJ. The GLJ Report has been prepared using certain commodity price assumptions (see “Statement of Reserves Data and Other Oil and Gas Information – Forecast Prices and Costs”). If we realize lower prices for crude oil, natural gas liquids and natural gas and they are substituted for the price assumptions utilized in those reserves reports, the present value of estimated future net revenues for our reserves and net asset value would be reduced and the reduction could be significant. The estimates contained herein and in the GLJ Report are based in part on the timing and success of activities we intend to undertake in future years. The reserves and estimated future net revenues contained herein and in the GLJ Report will be reduced in future years to the extent that such activities do not achieve the production performance set forth herein and in the GLJ Report.

Estimates of proved undeveloped reserves are sometimes based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

Estimates of Contingent Resources contained in the GLJ Report are subject to the definitions, disclaimers, contingencies and warnings set forth in “Appendix C – Contingent Resource and Prospective Resource Estimates”. There is no certainty that it will be commercially viable to produce any portion of the resources.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 58

Expansion into New Areas

Our operations and expertise are currently focused on oil and gas production and development in the Western Canadian Sedimentary Basin. In the future, we may acquire oil and gas properties outside this geographic area. In addition, we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines, or an interest in an oil sands project. Expansion of our activities into new areas may present new additional risks or alternatively, significantly increase the exposure to one or more of the present risk factors which may adversely affect our future operational and financial conditions.

Expiration of Licenses and Leases

Our properties are held in the form of licences and leases and working interests in licences and leases. If we or the holder of the license or lease fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each license or lease will be met. The termination or expiration of a license or lease or the working interest relating to a license or lease may have a material adverse effect on our results of operations and business. In addition title to the properties can become subject to dispute and defeat our claim to title over certain of our properties. Furthermore, there may be legislative changes which affect title, to the oil and natural gas properties we control that, if successful or made into law, could impair our activities on them and result in a reduction of the revenue received by us.

Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada. We are not aware that any material claims have been made in respect of our properties and assets; however, if a claim arose and was successful this could have an adverse effect on us and our operations.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The price we pay for the purchase of any material properties is based on engineering and economic estimates of the reserves made by management and independent engineers modified to reflect our technical and economic views. These assessments include a number of material factors and assumptions. Consequently, the reserves acquired may be less than expected, which could adversely impact funds from operations and the payment of dividends to Shareholders.

We make acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as our ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation. There is no assurance that we will be able to continue to complete acquisitions or dispositions of oil and natural gas properties which realize all the synergistic benefits expected.

Access to Our Offices and Properties

Our ability to carry on our business is dependent upon the ability of our employees to physically access our offices and properties. If access to our office and properties is interrupted then our ability to administer and manage our business may be materially and adversely affected.

Earnings Volatility

Our accounting policies conform to International Financial Reporting Standards (“IFRS”) which constitutes generally accepted accounting principles in Canada. Accounting under IFRS may result in non-cash charges and/or write-downs of net assets in the financial statements on a quarterly basis. Similarly, non-cash gains and recoveries of asset write-downs may also be recorded from time to time. Income statement volatility resulting from such non-cash gains and losses under IFRS may be viewed unfavourably by the market and could result in an inability to borrow funds and/or could result in a decline in the price of the Common Shares.

For more information as to ARC’s current accounting policies and future accounting policy changes, see Note 3 “Summary of Accounting Policies” and Note 4 “Future Accounting Policy Changes” in ARC’s audited consolidated financial statements as at and for the year ended December 31, 2016 which section is incorporated in this Annual Information Form by reference and is found on our SEDAR profile at www.sedar.com.

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Forward-Looking Information

Forward-Looking Information may not reflect actual outcomes.Shareholders and prospective investors are cautioned not to place undue reliance on the Corporation's forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown risk and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Additional information on the risks, assumption and uncertainties are found under the heading “Reader Advisory Regarding Forward-Looking Statements” of this Annual Information Form.

ADDITIONAL RISK FACTORS APPLICABLE TO RESIDENTS OF THE UNITED STATES AND OTHER NON-RESIDENTS OF CANADA

Limited Ability of Residents in the United States to Enforce Civil Remedies

ARC Resources is a corporation formed under the laws of Alberta, Canada and has its principal place of business in Canada. All of our Directors and all of our Officers and the representatives of the experts who provide services to us (such as our auditors and our independent reserve engineers), and all of our assets and all or a substantial portion of the assets of such persons are located outside the United States. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon such Directors, Officers and representatives of experts who are not residents of the United States or to enforce against them judgments of the United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as to the enforceability in Canada against ARC Resources or against any of our Directors, Officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or securities laws of any state within the United States.

Different Reporting Practices in Canada and the United States

We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the Securities and Exchange Commission by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the Securities and Exchange Commission and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes (before deduction of Crown and other royalties); however, we also follow the United States practice of separately reporting reserve volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves; whereas the Securities Exchange Commission requires that prices and costs be averaged for the 12 months prior to the date of the reserve report.

We have included in Appendix C to this the Annual Information Form estimates of Contingent Resources. Contingent Resources are classes of resources and should not be confused with reserves and are subject to the definitions, disclaimers and warnings set forth in Appendix C – Contingent Resource Estimates. The Securities and Exchange Commission prohibits the inclusion of Contingent Resource estimates in filings made with it. This prohibition does not apply to us because we are a Canadian foreign private issuer that reports with the SEC pursuant to the U.S.-Canadian multi-jurisdictional disclosure system.

As a consequence of the foregoing, our reserve estimates and production volumes in this Annual Information Form may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

Additional Taxation Applicable to Dividends Paid to Non-Residents

Cash dividends paid to a non-resident of Canada on Common Shares are subject to Canadian withholding tax at a rate of 25 per cent unless the rate is reduced under the provisions of an applicable double taxation treaty. Where a non-resident is a United States resident entitled to benefits of the Canada – United States Income Tax Convention,

ARC Resources Ltd. | 2016 | Annual Information Form | Page 60

1980 and is the beneficial owner of the dividends then the rate of Canadian withholding tax is generally reduced to 15 per cent.

Foreign Exchange Risk to Non-resident Shareholders

Our dividends are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, investors are subject to foreign exchange risk. To the extent that the Canadian dollar strengthens with respect to their currency, the amount of the dividend will be reduced when converted to their home currency.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Common Shares is Computershare Trust Company of Canada at its principal offices in Calgary and Toronto.

MATERIAL CONTRACTS

The following comprises particulars of every material contract of ARC that was entered into within the most recently completed financial year, or entered into before the most recently completed financial year which is still in effect, other than a contract entered into in the ordinary course of business: Amended and Restated Credit Agreement dated as of November 6, 2014, as amended on November 23, 2016; between ARC Resources and a syndicate of lenders, and an administrative agent, providing for an extendible revolving credit facility up to Cdn$950 million. The maturity date of the facility was extended to November 6, 2020 under the existing terms and revised credit limit on November 23, 2016.

1. Uncommitted Master Shelf Agreement dated as of November 16, 2000 between ARC Resources and various purchasers, as amended and restated on December 15, 2005 and as amended and restated on September 25, 2014 providing for the issuance and sale of up to an aggregate principal amount of US$350 million in notes of which US$9.4 million 5.42% Series C Notes due December 15, 2017, US$30.0 million 4.98% Series D Notes due March 5, 2019 and US$150 million 3.72% Series E Notes due September 25, 2026 are currently outstanding.

2. Note Purchase Agreement dated as of April 14, 2009 between ARC Resources and various purchasers, as amended January 1, 2011 with respect to US$67.5 million 7.19% Series C Notes due April 14, 2016, US$35 million 8.21% Series D Notes due April 14, 2021 and Cdn$29 million 6.50% Series E Notes due April 14, 2016 of which US$0 million, US$35 million and Cdn$0 million, respectively, are currently outstanding.

3. Note Purchase Agreement dated as of May 27, 2010 between ARC Resources and various purchasers, as amended January 1, 2011 with respect to US$150 million 5.36% Series F Notes due May 27, 2022, of which US$150 million is currently outstanding.

4. Note Purchase Agreement dated as of August 23, 2012 between ARC Resources and various purchasers with respect to US$60 million 3.31% Series G Notes due August 23, 2021, US$300 million 3.81% Series H Notes due August 23, 2024 and Cdn$40 million 4.49% Series I Notes due August 23, 2024, of which US$60 million, US$300 million and Cdn$40 million, respectively, is currently outstanding.

For more information in relation to these material contracts, see “Other Information Relating to Our Business – Borrowings”. Copies of each of these documents have been filed on our SEDAR profile at www.sedar.com.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 61

INTEREST OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under NI 51-102 by us during, or related to, our most recently completed financial year other than GLJ, our independent qualified reserves evaluator, and Deloitte LLP, our external auditor for the year ended December 31, 2016. As at the date hereof the designated professionals of GLJ, as a group, beneficially owned, directly or indirectly, less than one per cent of our outstanding securities, including the securities of our associates and affiliates.

Deloitte LLP, Chartered Accountants, Calgary, Alberta, have issued their audit opinion dated February 8, 2017, in respect of the Company’s consolidated financial statements as at December 31, 2016 and 2015 and for each of the years in the three-year period ended December 31, 2016. Deloitte  LLP  is  independent  with  respect  to the Company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of  Alberta and is independent within the  meaning  of  the applicable  rules  and  regulations adopted by the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board (United States).

In addition, none of the aforementioned persons or companies, nor any Director, Officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of ARC Resources or of any of our associate or affiliate entities. Grant A. Zawalsky, the Corporate Secretary of ARC Resources, is a partner of Burnet, Duckworth & Palmer LLP, which law firm renders legal services to us.

ADDITIONAL INFORMATION

Additional information including remuneration and indebtedness of Directors and Officers of ARC Resources, principal holders of the Common Shares and options to purchase Common Shares, will be contained in the Information Circular - Proxy Statement of the Corporation which relates to the Annual Meeting of Shareholders to be held on May 4, 2017. Additional financial information is provided in our consolidated financial statements and accompanying Management's Discussion and Analysis for the year ended December 31, 2016, which have been filed on our SEDAR profile at www.sedar.com. Other additional information relating to us may be found on our SEDAR profile at www.sedar.com.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 62

APPENDIX AForm 51-101F2

REPORT ON RESERVES DATA AND CONTINGENT RESOURCES DATABY

INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

To the Board of Directors of ARC Resources Ltd. (the “Company”):

1. We have evaluated the Company’s reserves data, and contingent resources data as at December 31, 2016. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2016, estimated using forecast prices and costs.The contingent resources data are risked estimates of volume of contingent resources and related risked net present value of future net revenue as at December 31, 2016, estimated using forecast prices and costs.

2. The reserves data, and contingent resources data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data, and contingent resources data based on our evaluation.

3. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”) maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

4. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data, and contingent resources data are free of material misstatement. An evaluation also includes assessing whether the reserves data, contingent resources data are in accordance with principles and definitions presented in the COGE Handbook.

5. The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2016, and identifies the respective portions thereof that we have evaluatedand reported on to the Company's Board of Directors:

Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation Report (MM/DD/YY)	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate – M$)
			Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	12/31/16	Canada	-	5,832,486	-	5,832,486

6. The following tables set forth the risked volume and risked net present value of future net revenue of contingent resources (before deduction of income taxes) attributed to contingent resources, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the Company's statement prepared in accordance with Form 51-101F1 and identifies the respective portions of the contingent resources data that we have evaluated and reported on to the Company's Board of Directors:

ARC Resources Ltd. | 2016 | Annual Information Form | Page 63

Classification	Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation Report (MM/DD/YY)	Location of Resources Other than Reserves (Country or Foreign Geographic Area)		Risked Net Present Value of Future Net Revenue (before income taxes, 10% discount rate – M$)
				Risked Volume (MMboe)	Audited	Evaluated	Total
Development Pending Contingent Resources (2C)	GLJ Petroleum Consultants	12/31/16	Canada	528.9		1,831,085	1,831,085

Classification	Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation Report (MM/DD/YY)	Location of Resources Other than Reserves (Country or Foreign Geographic Area)	Risked Volume (MMboe)
Contingent Resources Development Unclarified	GLJ Petroleum Consultants	12/31/16	Canada	914.3
Contingent Resources Development Not Viable	GLJ Petroleum Consultants	12/31/16	Canada	143.7

7. In our opinion, the reserves data, and contingent resources data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data and contingent resources data that we reviewed but did not audit or evaluate.

8. We have no responsibility to update our reports referred to in paragraphs 5 and 6 for events and circumstances occurring after the effective date of our reports.

9. Because the reserves data, and contingent resources data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 16, 2017

“Originally Signed by”

Bryan M. Joa, P. Eng.

Vice President

ARC Resources Ltd. | 2016 | Annual Information Form | Page 64

APPENDIX BREPORT OF MANAGEMENT AND DIRECTORS ONRESERVES DATA AND OTHER INFORMATION

FORM 51-101F3

Management of ARC Resources Ltd. (the “Company”) is responsible for the preparation and disclosure of information with respect to the Company's and its subsidiaries' oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, and includes, if disclosed in the statement required by item 1 of section 2.1 of NI 51-101, other information such as contingent resources and prospective resources data.

An independent qualified reserves evaluator has evaluated the Company's reserves data, contingent resources data. The report of the independent qualified reserves evaluator is presented below.

The Reserves Committee of the Board of Directors of the Company has

a) reviewed the Company's procedures for providing information to the independent qualified reserves evaluator;

b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

c) reviewed the reserves data, and contingent resources data with management and the independent qualified reserves evaluator.

The Reserves Committee of the Board of Directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved

a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data, contingent resources data, and other oil and gas information;

b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data, contingent resources data, prospective resources data; and

c) the content and filing of this report.

Because the reserves data and contingent resources data are based on judgments regarding future events, actual results will vary and the variations may be material.

(signed) “Myron Stadnyk”	(signed) “Terry Anderson”
Myron Stadnyk	Terry Anderson
President and Chief Executive Officer	Senior Vice President and Chief Operating Officer
(signed) “James Houck”	(signed) "Kathleen O’Neill"
James Houck	Kathleen O’Neill
Director and Chairof the Reserves Committee	Director and Member of the Reserves Committee
March 8, 2017

ARC Resources Ltd. | 2016 | Annual Information Form | Page 65

APPENDIX CCONTINGENT RESOURCE ESTIMATES

ARC engaged GLJ to provide an updated evaluation of, among other things, our Contingent Resources effective December 31, 2016, for our working interest in our northeast British Columbia Montney properties, including lands at Pouce Coupe across the provincial border in Alberta, which Contingent Resources are set forth and described below, all of which will be referred to as “NE BC Montney” for purposes of this Appendix. ARC owns an average 94per cent working interest in our NE BC Montney properties. The evaluation procedures employed by GLJ are in compliance with standards contained in the COGE Handbook and the GLJ Report is based on GLJ's January 1, 2017 forecast pricing. GLJ's January 1, 2017 forecast pricing as set forth under “Statement of Reserves Data and Other Oil and Gas Information - Forecast Prices and Costs” in the Annual Information Form to which this Appendix C is attached, is incorporated into this Appendix C by this reference. All applicable resource definitions are provided at the in the “Resource Definitions” section at the end of Appendix C.

Contingent Resources should not be confused with reserves and readers should review the definitions and notes set forth below. Actual tight oil, shale gas, and natural gas liquids resources may be greater than or less than the estimates provided herein. There is uncertainty that it will be commercially viable to produce any portion of the resources.

Summary of Risked Oil and Gas Contingent Resources as of December 31, 2016 – Forecast Prices and Costs

Contingent Resources (1)(2)(3)

Resources Project Maturity Sub-Class

Tight Oil

Shale Gas

NGLs

Oil Equivalent

Gross (Mbbl)

Net (Mbbl)

Gross (Bcf)

Net (Bcf)

Gross (Mbbl)

Net (Mbbl)

Gross (Mboe)

Net (Mboe)

Contingent (2C)

Development Pending

39,905

34,403

2,613

2,088

53,500

44,168

528,947

426,616

Development Unclarified

106,897

N/A

3,570

N/A

212,468

N/A

914,308

N/A

Total Economic Contingent Resources

146,802

N/A

6,183

N/A

265,968

N/A

1,443,255

N/A

DevelopmentNot Viable

1,140

N/A

569

N/A

47,637

N/A

143,664

N/A

1) All volumes listed in the table are risked, company gross sales volumes.

2) Refer to “Resource Definitions” in this Appendix C for detailed definitions of Contingent Resources, Development Pending, Development Unclarified and Development Not Viable.

3) Net values are only stated for Development Pending. Net values for the remaining sub-classes are N/A as economics were not run, therefore net volumes were not determined.

An estimate of risked net present value (“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. Subclasses of resources other than development pending are not included in the NPV values and therefore are not reflective of the value of the resource base.

SUMMARY OF RISKED NET PRESENT VALUE OF FUTURE NET REVENUES (CONTINGENT RESOURCES) AS OF DECEMBER 31, 2016 – FORECAST PRICES AND COSTS

	Risked Net Present Value of Future Net Revenue (1)
Resources Project Maturity Sub-Class($ millions)	Before Income TaxesDiscounted at % per Year						After Income TaxesDiscounted at % per Year
		0	5	10	15	20		0	5	10	15	20
Contingent (2C) Development Pending		10,693	4,068	1,831	925	508		7,841	2,924	1,277	620	323

1) NPV as per GLJ Independent Resources Evaluation as of December 31, 2016 and based on GLJ forecast pricing at January 1, 2017.

ARC Resources Ltd. | 2016 | Annual Information Form | Page 66

Reserves and Resources Reconciliation

Resources will generally move from prospective resources to contingent resources, and then to reserves, and ultimately to production.Approximately 73 MMboe of contingent resources were moved to reserves due to the removal of the chance of development risk. This was due to increased certainty in the resource economics, increased certainty in the development plans, and/or increased certainty in the development timeframe. 

Projects for Which Resources Are Being Attributed

The Montney formation in northeast British Columbia and Alberta has been identified as a world-class 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 744 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 (each, an “Evaluated Area” and, collectively, “Evaluated Areas”). GLJ has prepared best estimates of risked estimates of contingent resources (“CR”) associated with the Evaluated Areas. This evaluation is effective December 31, 2016.

The estimated cost to bring on commercial production from the Development Pending CR for all three product types is approximately $4.0 billion (discounted at 10 per cent is approximately $1.4 billion). The expected timeline to bring these resources onto production ranges from two years to nineyears depending on the Evaluated Area. ARC’s Development Pending CR will represent properties where specific development plans have been made, in areas adjacent to or extending from reserve lands, which have not yet been delineated. These resources 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.

Chance of Discovery and Development Risk

The Evaluated Areas with CR were risked for the chance of commerciality (CoC), which is defined as follows:

CoC = chance of development (CoDev) × chance of discovery (CoDis)

wherein CoD is for contingent resources is equal to one for all CR.

The chance of development is the estimated probability that, once discovered, a known accumulation will be

commercially developed. Five factors have been considered in determining the CoDev as follows:

CoDev = Ps (Economic Factor) × Ps (Technology Factor) × Ps (Development Plan Factor) × Ps (Development Timeframe Factor) × Ps (Other Contingency Factor)

wherein Ps is the probability of success

The five factors were assessed for each of the Evaluated Areas. The following factors were assessed for ARC’s CR to be sub-classified and considered as Development Pending CR, Development Unclarified CR or Development Not Viable CR:

- Economic Factor: for Development Pending the associated development projects had robust economics (i.e. strong rate of returns), and as such were assigned a factor of one. The remaining CR sub-classes have factors ranging from 0.75 to 1.0.

- Technology Factor: ARC’s NEBC Montney will be developed utilizing established technology, therefore, a technology factor of one is utilized for all resource CR sub-classes.

- Development Plan Factor: detailed development plans and costs were prepared and are in place. This factor ranges from 0.90 to 1.0 for Development Pending CR. Factors less than one account for projects where final pad placement and well locations are less certain. For the remaining CR sub-classes, the Development Plan Factors range from 0.70 to 0.95 based on the level of details provided.

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- Development Timeframe Factor: several core areas within the Evaluated Areas have portions of the PIIP volume developed and producing, with proved and probable reserves assigned. Timing for the CR portions of these projects will depend on the pace of continued development (including allocation of funds), available throughput capacity in existing facilities, or construction of additional facilities. Development Pending projects have been assigned Development Timeframe Factors ranging from 0.90 to 0.95 reflecting the apparent certainty in timing estimates. For the remaining CR sub-classes, the Timeframe Factors assigned range from 0.70 to 0.90.

- Other Contingency Factor: for reserves to be assessed, all contingencies must be eliminated. With respect to contingent resources, this factor captures major contingencies, usually beyond the control of ARC, other than those captured by economic status, technology status, project evaluation scenario status and the development timeframe. The Other Contingency Factor has been assessed as one for all CR sub-classes.

These factors may be inter-related and care has been taken to ensure that risks are appropriately accounted. The following table summarizes the Chance of Development applied to CR based on the factors assessed.

2016 Contingent ResourcesRisked CR, Unrisked CR and Chance of Development (1)(2)	Chance of Development			Best Estimate Unrisked		Best Estimate Risked
Shale Gas (Tcf)
Development Pending CR		91	%		2.9		2.6
Development Unclarified CR		74	%		4.9		3.6
Development Not Viable CR		46	%		1.2		0.6
NGLs (MMbbl)
Development Pending CR		91	%		58.6		53.5
Development Unclarified CR		74	%		286.7		212.5
Development Not Viable CR		49	%		97.7		47.6
Tight Oil (MMbbl)
Development Pending CR		95	%		42.0		39.9
Development Unclarified CR		69	%		154.3		106.9
Development Not Viable CR		95	%		1.2		1.1
Total (MMboe)
Development Pending CR		92	%		577.3		528.9
Development Unclarified CR		73	%		1,249.7		914.3
Development Not Viable CR		47	%		303.1		143.7

1) All volumes listed in the table are company gross sales volumes.

2) Refer to “Resource Definitions” in this Appendix C for detailed definitions of Contingent Resources, Development Pending, Development Unclarified and Development Not Viable.

Risks and Significant Positive and Negative Factors

Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in order for Contingent 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 natural gas, natural gas liquids, and oil prices that would curtail the economics of development, the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, access to market and the effectiveness of fracturing technology and applications.

Furthermore, it should be understood that CR estimates reflect data as of the effective date. Although only best estimates are reported, it should be understood that there is a significant degree of uncertainty in these estimates. Additional data may justify upward or downward revisions to the estimates, which in turn would impact CR estimates.

For more information, see “Risk Factors – Risk Relating to our Business and Operations – There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves and resources including many factors beyond our control” in the Annual Information Form to which this Appendix C is attached.

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Contingencies

In the NE BC Montney, the primary contingencies that prevent the CR from being classified as reserves are for Management and the Board to ascertain commercial production rates, then develop firm plans, including timing, infrastructure, and the commitment of capital. Additional contingencies are related to the current lack of infrastructure, mostly gas processing but in some cases transportation, required to develop the resources in a relatively quick time frame. As continued delineation occurs and plans are firmed up, some Contingent Resources are expected to be re-classified to reserves.

Projects have been defined to develop the resources in the NE BC Montney for the Development Pending CR at the evaluation date. Such projects, in the case of the NE BC Montney, 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, ARC’s short-term and long-term view of natural gas, natural gas liquids and oil prices, the results of exploration and development activities of ARC and others in the area and infrastructure capacity constraints.

Resource Definitions

The following are excerpts from the definitions of resources and reserves, contained in Section 5 of the COGE Handbook, which is referenced by the Canadian Securities Administrators in “National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities”.

a) Fundamental Resource Definitions

Contingent Resources or CR 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. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.

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. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity.

b) Uncertainty Categories for Resource Estimates

The range of uncertainty of estimated recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. Resources should be provided as low, best, and high estimates as follows:

Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

Best Estimate: This 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.

High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic

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methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

This approach to describing uncertainty may be applied to reserves and contingent resources. There may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production. However, it is useful to consider and identify the range of potentially recoverable quantities independently of such risk.

c) Discovered and Commercial Status and Risks Associated with Resource Estimates

Discovery Status

Total petroleum initially in place is first subdivided based on the discovery status of a petroleum accumulation. Discovered PIIP, production, reserves, and contingent resources are associated with known accumulations. Recognition as a known accumulation requires that the accumulation be penetrated by a well and have evidence of the existence of petroleum. COGEH Volume 2, Sections 5.3 and 5.4, provides additional clarification regarding drilling and testing requirements relating to recognition of known accumulations. On the other hand, Prospective resources is undiscovered PIIP which is associated with accumulations yet to be discovered.

Commercial Status

Commercial status differentiates reserves from contingent resources. The following outlines the criteria that should be considered in determining commerciality:

· economic viability of the related development project;

· a reasonable expectation that there will be a market for the expected sales quantities of production required to justify development;

· evidence that the necessary production and transportation facilities are available or can be made available;

· evidence that legal, contractual, environmental, governmental, and other social and economic concerns will allow for the actual implementation of the recovery project being evaluated;

· a reasonable expectation that all required internal and external approvals will be forthcoming. Evidence of this may include items such as signed contracts, budget approvals, and approvals for expenditures, etc.;

· evidence to support a reasonable timetable for development. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While five years is recommended as a maximum time frame for classification of a project as commercial, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons or to meet contractual or strategic objectives.

Commercial Risk Applicable to Resource Estimates

Estimates of recoverable quantities are stated in terms of the sales products derived from a development program, assuming commercial development. It must be recognized that reserves and contingent resources involve different risks associated with achieving commerciality. The likelihood that a project will achieve commerciality is referred to as the “chance of commerciality.” The chance of commerciality varies in different categories of recoverable resources as follows:

Reserves: To be classified as reserves, estimated recoverable quantities must be associated with a project(s) that has demonstrated commercial viability. Under the fiscal conditions applied in the estimation of reserves, the chance of commerciality is effectively 100 percent.

Contingent Resources: Not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on the forecast of fiscal conditions over the life of the project. For contingent resources the risk component relating to the likelihood that an accumulation will be commercially developed is referred to as the “chance of development.” For contingent resources the chance of commerciality is equal to the chance of development.

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d) Recovery Technology Status

Established Technology: A recovery method that has been proven to be successful in commercial applications in the subject reservoir and is a prerequisite for assigning reserves.

Technology Under Development: A recovery process that has been determined to be technically viable via field test and is being field tested further to determine its economic viability in the subject reservoir. Contingent resources may be assigned if the project provides information that is sufficient and of a quality to meet the requirements for this resource class.

Experimental Technology: A technology that is being field tested to determine the technical viability of applying a recovery process to unrecoverable discovered petroleum initially-in-place in a subject reservoir. It cannot be used to assign any class of recoverable resources (i.e., reserves and contingent resources).

e) Economic Status of Resource Estimates

By definition, reserves are commercially (and hence economically) recoverable. A portion of contingent resources may also be associated with projects that are economically viable but have not yet satisfied all requirements of commerciality. Accordingly, it may be a desirable option to subclassify contingent resources by economic status:

Economic Contingent Resources are those contingent resources that are currently economically recoverable. The CR sub-classes included are Development Pending CR, Development on Hold CR, and Development Unclarified CR. 

Sub-Economic Contingent Resources are those contingent resources that are not currently economically recoverable. The CR sub-class included is Development Not Viable. 

Where evaluations are incomplete such that it is premature to identify the economic viability of a project, it is acceptable to note that project economic status is “undetermined” (i.e., “contingent resources – economic status undetermined”).

In examining economic viability, the same fiscal conditions should be applied as in the estimation of reserves, i.e., specified economic conditions, which are generally accepted as being reasonable (refer to COGEH Volume 2, Section 5.8).

f) Project Maturity Sub-Classes for Contingent Resources

Development Pending: Where resolution of the final conditions for development is being actively pursued (high chance of development).

Development on Hold: Where there is a reasonable chance of development but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator.

Development Unclarified: When the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties.

Development Not Viable: Where no further data acquisition or evaluation is currently planned and hence there is a low chance of development.

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APPENDIX DMANDATE OF THE AUDIT COMMITTEE (April 28, 2016)

MANDATE OF THE AUDIT COMMITTEE

Role and Objective

The Audit Committee (the “Committee”) is a committee of the Board of Directors of ARC Resources Ltd. (the “Corporation”) to which the Board has delegated its responsibility for oversight of the nature and scope of the annual audit, management's reporting on internal accounting standards and practices, financial information and accounting systems and procedures, financial reporting and statements and recommending, for Board of Director approval, the audited financial statements and other mandatory disclosure releases containing financial information.  The objectives of the Committee, with respect to the Corporation and its subsidiaries, are as follows:

· To assist Directors to meet their responsibilities in respect of the preparation and disclosure of the financial statements of the Corporation and related matters.

· To provide better communication between Directors and external auditors.

· To ensure the external auditors' independence.

· To review management’s implementation and maintenance of an effective system of internal control over financial reporting and disclosure control over financial reporting.

· To increase the credibility and objectivity of financial reports.

· To facilitate in-depth discussions between Directors on the Committee, management and external auditors.

The primary responsibility for the financial reporting, information systems, risk management and internal and disclosure controls of the Corporation is vested in management and overseen by the Board of Directors of the Corporation.  At each meeting, the Committee may meet separately with management and will meet in separate, closed sessions with the external auditors and then with the independent Directors in attendance.

Mandate and Responsibilities of Committee

Financial Reporting and Related Public Disclosure

1. It is a primary responsibility of the Committee to review and recommend for approval to the Board of Directors the annual and quarterly financial statements of the Corporation.  The Committee is also to review and recommend to the Board of Directors for approval the financial statements and related information included in prospectuses, management discussion and analysis (MD&A), financial press releases, information circular-proxy statements and annual information forms (AIF). The process should include but not be limited to:

a. reviewing changes in accounting principles, or in their application, which may have a material impact on the current or future years' financial statements;

b. reviewing significant management judgments and estimates that may be material to financial reporting including alternative treatments and their impacts;

c. reviewing the presentation and impact of any significant risks and uncertainties that may be material to financial reporting including alternative treatments and their impacts;

d. reviewing accounting treatment of significant, unusual or non-recurring transactions;

e. reviewing adjustments raised by the external auditors, whether or not included in the financial statements;

f. reviewing unresolved differences between management and the external auditors;

g. determining through inquiry if there are any related party transactions and ensure the nature and extent of such transactions are properly disclosed; and

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h. reviewing all financial reporting relating to risk exposure including the identification, monitoring and mitigation of business risk and its disclosure.

2. The Committee shall satisfy itself that adequate procedures are in place for the review of the Corporation's public disclosure of financial information from the Corporation's financial statements and periodically assess the adequacy of those procedures.

Internal Controls Over Financial Reporting and Information Systems

3. It is the responsibility of the Committee to satisfy itself on behalf of the Board with respect to the Corporation's internal control over financial reporting and information systems.  The process should include but not be limited to:

a. inquiring as to the adequacy and effectiveness of the Corporation’s system of internal controls over financial reporting and review the evaluation of internal controls over financial reporting by external auditors;

b. establishing procedures for the confidential, anonymous submission by employees of the Corporation of concerns relating to accounting, internal control over financial reporting, auditing or Code of Business Conduct and Ethics matters and periodically review a summary of complaints and their related resolution; and

c. establishing procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls, or auditing matters.

Extractive Sector Transparency Measures Act

4. It is the responsibility of the Committee to satisfy itself on behalf of the Board to review management’s process for certification under the Extractive Sector Transparency Measures Act (Canada).

External Auditors

5. With respect to the appointment of external auditors by the Board, the Committee shall:

a. be directly responsible for overseeing the work of the external auditors engaged for the purpose of issuing an auditors' report or performing other audit, review or attest services for the Corporation, including the resolution of disagreements between management and the external auditor regarding financial reporting;

b. review the terms of engagement of the external auditors, including the appropriateness and reasonableness of the auditors' fees;

c. review and evaluate annually the external auditors’ performance, and periodically, (at least every five years) conduct a comprehensive review of the external auditor;

d. recommend to the Board appointment of external auditors and the compensation of the external auditors;

e. when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change;

f. review and approve any non-audit services to be provided by the external auditors' firm and consider the impact on the independence of the auditors; between scheduled meetings, the Chair of the Committee is authorized to approve all audit related services and non-audit services provided by the external auditors for individual engagements with estimated fees of $50,000 and under; and shall report all such approvals to the Committee at its next scheduled meeting;

g. inquire as to the independence of the external auditors and obtain, at least annually, a formal written statement delineating all relationships between the external auditors and the Corporation as contemplated by Independence Standards Board No. 1;

h. review the Annual Report of the Canadian Public Accountability Board (“CPAB”) concerning audit quality in Canada and discuss implications for the Corporation;

i. review any reports issued by CPAB regarding the audit of the Corporation; and

j. discuss with the external auditors, without management being present, the quality of the Corporation’s financial and accounting personnel, the completeness and accuracy of the Corporation’s financial

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statements and elicit comments of senior management regarding the responsiveness of the external auditors to the Corporation’s needs.

6. The Committee shall review with the external auditors (and the internal auditor if one is appointed by the Corporation) their assessment of the internal control over financial reporting of the Corporation, their written reports containing recommendations for improvement of internal control over financial reporting and other suggestions as appropriate, and management's response and follow-up to any identified weaknesses.

7. The Committee shall also review and approve annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of the Corporation and its subsidiaries.

Compliance

8. It is the responsibility of the Committee to review management’s process for the certification of annual and interim financial reports in accordance with required securities legislation.

9. It is the responsibility of the Committee to ascertain compliance with covenants under loan agreements.

10. The Committee shall review the Corporation’s compliance with all legal and regulatory requirements as it pertains to financial reporting, taxation, internal control over financial reporting and any other area the Committee considers to be appropriate relative to its mandate or as may be requested by the Board of Directors.

Other Matters

11. It is the responsibility of the Committee to review and approve the Corporation's hiring policies regarding partners, employees and former partners and employees of the present and external auditors of the Corporation.

12. The Committee may also review any other matters that the Audit Committee feels are important to its mandate or that the Board chooses to delegate to it.

13. The Committee shall undertake annually a review of this mandate and make recommendations to the Policy and Board Governance Committee as to proposed changes.

Composition

14. This Committee shall be composed of at least three individuals appointed by the Board from amongst its members, all of which members will be independent (within the meaning of Section 1.4 and 1.5 of National Instrument 52-110 Audit Committees) unless the Board determines to rely on an exemption in NI 52-110.  “Independent” generally means free from any business or other direct or indirect material relationship with the Corporation that could, in the view of the Board, be reasonably expected to interfere with the exercise of the member's independent judgment.

15. The Chair of the Committee is appointed by the Board of Directors.

16. A quorum shall be a majority of the members of the Committee.

17. All of the members must be financially literate within the meaning of NI 52-110 unless the Board has determined to rely on an exemption in NI 52-110.  Being “financially literate” means members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Corporation's financial statements.

Meetings

18. The Committee shall meet at least four times per year and/or as deemed appropriate by the Committee Chair.

19. The Committee shall meet not less than quarterly with the auditors, independent of the presence of management.

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20. Agendas, with input from management, shall be circulated to Committee members and relevant management personnel along with background information on a timely basis prior to the Committee meetings.

21. The Chief Executive Officer and the Chief Financial Officer or their designates shall be available to attend at all meetings of the Committee upon the invitation of the Committee.

22. The Controller and such other staff as appropriate to provide information to the Committee shall attend meetings upon invitation by the Committee.

Reporting / Authority

23. Following each meeting, in addition to a verbal report, the Committee will report to the Board by way of providing copies of the minutes of such Committee meeting at the next Board meeting after a meeting is held (these may still be in draft form).

24. Supporting schedules and information reviewed by the Committee shall be available for examination by any director.

25. The Committee shall have the authority to investigate any financial activity of the Corporation and to communicate directly with the internal and external auditors.  All employees are to cooperate as requested by the Committee.

26. The Committee may retain, and set and pay the compensation for, persons having special expertise and/or obtain independent professional advice to assist in fulfilling its duties and responsibilities at the expense of the Corporation.

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