UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 40‑F

 

 

☐

REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

 

OR

☒

ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

7

 

 

 

For the fiscal year ended December 31, 2018

Commission File Number 001‑15150

 

ENERPLUS CORPORATION

(Exact name of Registrant as specified in its charter)

Alberta, Canada

(Province or other jurisdiction of incorporation or organization)
1311

(Primary Standard Industrial Classification Code Number (if applicable))
N/A

(I.R.S. Employer Identification Number (if applicable))
The Dome Tower, 3000, 333 ‑  7 th  Avenue S.W.
Calgary, Alberta, Canada T2P 2Z1
(403) 298‑2200

(Address and telephone number of Registrant’s principal executive offices)
CT Corporation System
28 Liberty Street
New York, New York 10005
(212) 894‑8940

(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

 

 

 

 

Title of each class

Name of each exchange on which registered

 

Common Shares

Toronto Stock Exchange
The New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports, indicate by check mark the information filed with this Form:

 

 

☒ Annual information form

☒ Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

239,411,102 Common Shares

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒            No ☐

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes ☒            No ☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.                                                  

☐

†   The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

 

 

 

FORWARD‑LOOKING STATEMENTS

 

This Annual Report on Form 40‑F contains or incorporates by reference forward‑looking statements relating to future events or future performance. In some cases, forward‑looking statements can be identified by terminology such as “may”,  “should”,  “expects”,  “projects”,  “plans”,  “anticipates” and similar expressions. These statements represent management’s expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of the Registrant. Undue reliance should not be placed on these forward‑looking statements which are based upon management’s assumptions and are subject to known and unknown risks and uncertainties which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward‑looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. For a description of some of these risks, uncertainties, events and circumstances, readers should review the disclosure under the heading “Risk Factors” in the Registrant’s Annual Information Form for the year ended December 31, 2018, which is attached as Exhibit 99.1 to this Annual Report on Form 40‑F, and under the heading “Risk Factors and Risk Management” in the Registrant’s Management’s Discussion and Analysis for the year ended December 31, 2018, which is attached as Exhibit 99.3 to this Annual Report on Form 40‑F, and is incorporated by reference herein. Other than as required by applicable law, the Registrant undertakes no obligation to update publicly or revise any forward‑looking statements contained herein and such statements are expressly qualified by the cautionary statement.

 

ANNUAL INFORMATION FORM, AUDITED ANNUAL CONSOLIDATED
FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS

 

A. Annual Information Form

 

The Registrant’s Annual Information Form for the year ended December 31, 2018 is attached as Exhibit 99.1 to this Annual Report on Form 40‑F and is incorporated by reference herein.

 

B. Audited Annual Consolidated Financial Statements

 

The Registrant’s audited annual consolidated financial statements for the year ended December 31, 2018, including the report of the independent registered public accounting firm with respect thereto, are attached as Exhibit 99.2 to this Annual Report on Form 40‑F and are incorporated by reference herein.

 

C. Management’s Discussion and Analysis

 

The Registrant’s Management’s Discussion and Analysis for the year ended December 31, 2018 is attached as Exhibit 99.3 to this Annual Report on Form 40‑F and is incorporated by reference herein.

 

DISCLOSURE REGARDING CONTROLS AND PROCEDURES

 

A. Disclosure Controls and Procedures

 

As of the end of the Registrant’s fiscal year ended December 31, 2018, an evaluation of the effectiveness of the Registrant’s  “disclosure controls and procedures” (as such term is defined in Rules 13a‑15(e) and 15d‑15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the Registrant’s principal executive officer and principal financial officer. Based upon that evaluation, the Registrant’s principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the Registrant’s disclosure controls and procedures (which include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrant in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Registrant’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow for timely decisions regarding required disclosure) are effective to ensure that the information required to be disclosed by the Registrant in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

 

 

B. Management’s Annual Report on Internal Control Over Financial Reporting

 

The Registrant’s report of management on the Registrant’s internal control over financial reporting is included under the heading “Management’s Report on Internal Control Over Financial Reporting” contained in Exhibit 99.2 to this Annual Report on Form 40‑F, which report of management is incorporated by reference herein.

 

C. Attestation Report of the Independent Registered Public Accounting Firm

 

The attestation report of the independent registered public accounting firm on the effectiveness of internal control over financial reporting is included under the heading “Report of Independent Registered Public Accounting Firm” contained in Exhibit 99.2 to this Annual Report on Form 40‑F, which attestation report is incorporated by reference herein.

 

D. Changes in Internal Control over Financing Reporting

 

During the fiscal year ended December 31, 2018, there were no changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

 

NOTICES PURSUANT TO REGULATION BTR

 

None.

 

AUDIT COMMITTEE FINANCIAL EXPERT

 

The board of directors of the Registrant has determined that Mr. Robert B. Hodgins, a member and the chairman of the Registrant’s Audit & Risk Management Committee, and Mr. Jeffrey W. Sheets, a member of the Registrant’s Audit & Risk Management Committee, are “audit committee financial experts” (as such term is defined by the rules and regulations of the Securities and Exchange Commission) and are “independent” (as that term is defined by the New York Stock Exchange’s listing standards applicable to the Registrant).

 

The Securities and Exchange Commission has indicated that the designation or identification of a person as an “audit committee financial expert” does not (i) mean that such person is an “expert” for any purpose, including without limitation for purposes of Section 11 of the Securities Act of 1934, (ii) impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the audit committee and the board of directors in the absence of such designation or identification, or (iii) affect the duties, obligations or liability of any other member of the audit committee or the board of directors.

 

CODE OF ETHICS

 

The Registrant has adopted a “code of ethics” (as that term is defined by the rules and regulations of the Securities and Exchange Commission), entitled the “Code of Business Conduct” (as amended to the date of this Annual Report on Form 40‑F, the “Code of Business Conduct”), that applies to each director, officer (including its principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions), employee and consultant of the Registrant. The Registrant has amended the Code of Business Conduct effective January 7, 2019. There were no amendments made to the Code of Business Conduct of a substantive nature.  During the fiscal year ended December 31, 2018, there were no waivers, including implicit waivers, granted from any provision of the Code of Business Conduct that applied to the Registrant’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.

 

The Code of Business Conduct is attached as Exhibit 99.11 to this Annual Report on Form 40‑F and is incorporated by reference herein.

 

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES AND
PRE‑APPROVAL POLICIES AND PROCEDURES

 

The aggregate fees paid by the Registrant to the Registrant’s  external auditors, for professional services rendered in the Registrant’s last two fiscal years are as follows:

 

 

 

 

 

 

 

 

 

 

2018

 

2017

 

 

 

(in Cdn$ thousands)

 

Audit fees (1)

    

662.0 

    

742.5

 

Tax fees ( 2 )

 

43.1

 

125.8

 

All other fees ( 3 )

 

—

 

15.2

 

Total

 

705.1 

 

883.5

 

 

(1)

Audit fees were for professional services rendered for the audit of the Registrant’s annual financial statements and reviews of the Registrant’s quarterly financial statements, as well as services provided in connection with statutory and regulatory filings or engagements.

 

(2)

Tax fees were for tax compliance, tax advice and tax planning. 

 

(3)

All other fees are fees for products and services provided by the Reigistrant’s external auditors other than those described as “Audit fees”,  “Audit‑related fees” and “Tax fees”. For 2017, other fees include french translation services.

 

The Registrant’s Audit & Risk Management Committee has implemented a policy restricting the services that may be provided by the Registrant’s auditors and the fees paid to the Registrant’s auditors. Prior to the engagement of the Registrant’s auditors to perform both audit and non‑audit services, the Audit & Risk Management Committee pre‑approves the provision of the services. In making their determination regarding non‑audit services, the Audit & Risk Management Committee considers the compliance with the policy and the provision of non‑audit services in the context of avoiding an adverse impact on auditor independence. All audit and non‑audit fees paid to KPMG LLP, post their appointment as auditor in 2017, and all audit and non-audit fees paid to Deloitte LLP in 2017 were pre‑approved by the Registrant’s Audit & Risk Management Committee and none were approved on the basis of the de minimis exemption set forth in Rule 2‑01(c)(7)(i)(C) of Regulation S‑X. Based on the Audit & Risk Management Committee’s discussions with management and the independent auditors, the committee is of the view that the provision of the non‑audit services by KPMG LLP described above is compatible with maintaining that firm’s independence from the Registrant.

 

OFF‑BALANCE SHEET ARRANGEMENTS

 

The Registrant has no off‑balance sheet arrangements that have or are reasonably likely to have a current or future effect on the Registrant’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

 

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

 

The Registrant has the following contractual obligations, which are set forth in the table below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Payments due by period
(in Cdn$ thousands)

 

Contractual Obligations

 

Total

 

2019

 

2020 to 2021

 

2022 to 2023

 

2024 +

 

Senior unsecured notes (1)

 

$

696,850 

 

$

60,001

 

$

222,556 

 

$

218,465

 

$

195,828 

 

Transportation commitments ( 2 )

 

 

367,646 

 

 

36,817

 

 

72,053 

 

 

61,727

 

 

197,049

 

Processing commitments

 

 

16,174

 

 

3,506

 

 

4,693 

 

 

3,038

 

 

4,937

 

Drilling and completions commitment

 

 

51,433

 

 

20,005 

 

 

31,428

 

 

—

 

 

—

 

Office lease commitments

 

 

73,746

 

 

9,421 

 

 

21,808

 

 

22,781

 

 

19,736 

 

Sublease recoveries

 

 

(15,405)

 

 

(3,151)

 

 

(6,599)

 

 

(4,154)

 

 

(1,501)

 

  Net office lease commitments

 

 

58,341

 

 

6,270

 

 

15,209

 

 

18,627

 

 

18,235

 

Total commitments ( 3 )( 4 )

 

$

1,190,444

 

$

126,599

 

$

345,939 

 

$

301,857

 

$

416,049

 

 

 

Notes:

 

(1)

Interest payments have not been included.

 

(2)

Includes additional firm transportation commitments executed subsequent to year-end.

 

(3)

Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

 

(4)

U.S. dollar commitments have been converted to Canadian dollars using the December 31, 2018 foreign exchange rate of US$1.00 =  Cdn$1.36.

 

Additional disclosure regarding the Registrant’s contractual obligations is provided under the heading “Liquidity and Capital Resources — Commitments” in the Registrant’s Management’s Discussion and Analysis for the year ended December 31, 2018 attached as Exhibit 99.3 to this Annual Report on Form 40‑F, which disclosure is incorporated by reference herein, and in Note 15 to the Registrant’s audited annual consolidated financial statements for the year ended December 31, 2018 attached as Exhibit 99.2 to this Annual Report on Form 40‑F, which note is incorporated by reference herein.

 

IDENTIFICATION OF THE AUDIT COMMITTEE

 

The Registrant has a separately‑designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act. The members of the Registrant’s Audit & Risk Management Committee are Robert B. Hodgins (as Chairman), Michael R. Culbert, Susan M. MacKenzie, Glen D. Roane, and Jeffrey W. Sheets. Elliott Pew, the chairman of the board of directors of the Registrant, is an ex officio member of the Audit & Risk Management Committee.

 

COMPLIANCE WITH NYSE CORPORATE GOVERNANCE RULES

 

The Registrant has reviewed the New York Stock Exchange’s corporate governance rules and confirms that the Registrant’s corporate governance practices are not significantly nor materially different than those required of domestic companies under the New York Stock Exchange’s listing standards.

 

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

 

A. Undertaking

 

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40‑F; the securities in relation to which the obligation to file an annual report on Form 40‑F arises; or transactions in said securities.

 

B. Consent to Service of Process

 

1.

The Registrant previously filed with the Commission a Form F‑X in connection with the class of securities in relation to which the obligation to file this report arises.

 

2.

Any change to the name or address of the Registrant’s agent for service shall be communicated promptly to the Commission by amendment to Form F‑X referencing the file number of the Registrant.

 

 

SIGNATURES

 

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40‑F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

 

 

ENERPLUS CORPORATION

 

 

 

 

By:

/s/ Ian C. Dundas

 

 

Ian C. Dundas

 

 

President and Chief Executive Officer

 

Date: February 22, 2019

 

 

EXHIBIT INDEX

 

 

 

 

99.1

   

Annual Information Form for the year ended December 31, 2018 dated February 22, 2019.

99.2

 

Audited annual consolidated financial statements for the year ended December 31, 2018.

99.3

 

Management’s Discussion and Analysis for the year ended December 31, 2018.

99.4

 

Consent of Independent Registered Public Accounting Firm.

99.5

 

Consent of McDaniel & Associates Consultants Ltd.

99.6

 

Consent of Netherland, Sewell & Associates, Inc.

99.7

 

Certification of the Chief Executive Officer pursuant to Rule 13a‑14(a) or Rule 15d‑14(a) of the Securities Exchange Act of 1934.

99.8

 

Certification of the Chief Financial Officer pursuant to Rule 13a‑14(a) or Rule 15d‑14(a) of the Securities Exchange Act of 1934.

99.9

 

Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.

99.10

 

Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.

99.11

 

Code of Business Conduct.

99.12

 

Supplemental Information About Oil and Gas Producing Activities.

99.13

 

Consent of Predecessor Independent Registered Public Accounting Firm.

101

 

Interactive Data File.

 

 

 

EXHIBIT 99.5

 

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

 

 

We hereby consent to the use of our name in the Annual Report on Form 40-F (the "Annual Report") of Enerplus Corporation (the "Registrant").  We hereby further consent to the inclusion in the Annual Report of the Registrant's Annual Information Form dated February 22, 2019 for the year ended December 31, 2018, which document makes reference to our firm and our reports dated February 7, 2019, evaluating the Registrant's oil, natural gas and natural gas liquids interests effective December 31, 2018.

 

 

 

 

Calgary, Alberta, Canada

February 20, 2019

MCDANIEL & ASSOCIATES CONSULTANTS LTD.

 

 

 

/s/ Brian Hamm

 

Brian Hamm, P.Eng.

 

President & CEO

 

 

 

Exhibit 99.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PICTURE 4

 

 

 

 

ANNUAL INFORMATION FORM

 

 

For the year ended December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

February 22, 2019

 

 

 

 

 

 

TABLE OF CONTENTS

Page

 

 

 

 

GLOSSARY OF TERMS  

1

ABBREVIATIONS AND CONVERSIONS  

3

PRESENTATION OF OIL AND GAS RESERVES, CONTINGENT RESOURCES, AND PRODUCTION INFORMATION  

4

Note To Reader Regarding Oil And Gas Information, Definitions And National Instrument 51-101  

4

Disclosure Of Reserves And Production Information  

4

Barrels Of Oil And Cubic Feet Of Gas Equivalent  

5

Interests In Reserves, Contingent Resources, Production, Wells And Properties  

5

Reserves Categories And Levels Of Certainty For Reported Reserves  

5

Development And Production Status  

6

Description Of Price And Cost Assumptions  

6

PRESENTATION OF FINANCIAL INFORMATION  

6

FORWARD-LOOKING STATEMENTS AND INFORMATION  

6

CORPORATE STRUCTURE  

9

Enerplus Corporation  

9

Material Subsidiaries  

9

Organizational Structure  

9

GENERAL DEVELOPMENT OF THE BUSINESS  

10

Developments In  The Past Three Years  

10

BUSINESS OF THE CORPORATION  

11

Overview  

11

Summary Of Principal Production Locations  

11

Capital Expenditures And Costs Incurred  

12

Exploration And Development Activities  

13

Oil And Natural Gas Wells And Unproved Properties  

13

Description Of Properties  

14

Quarterly Production History  

16

Quarterly Netback History  

17

Tax Horizon  

18

Marketing Arrangements And Forward Contracts  

18

OIL AND NATURAL GAS RESERVES  

20

Summary Of Reserves  

20

Forecast Prices And Costs  

23

Undiscounted Future Net Revenue By Reserves Category  

23

Net Present Value Of Future Net Revenue By Reserves Category And Product Type  

24

Estimated Production For Gross Reserves Estimates  

25

Future Development Costs  

26

Reconciliation Of Reserves  

26

Undeveloped Reserves  

28

Significant Factors Or Uncertainties  

29

Proved And Probable Reserves Not On Production  

29

SUPPLEMENTAL OPERATIONAL INFORMATION  

30

Safety And Social Responsibility  

30

Insurance  

32

Personnel  

32

DESCRIPTION OF CAPITAL STRUCTURE  

33

Common Shares  

33

Preferred Shares  

33

Shareholder Rights Plan  

33

Senior Unsecured Notes  

34

Bank Credit Facility  

34

DIVIDENDS  

35

Dividend Policy And History  

35

Stock Dividend Program  

35

INDUSTRY CONDITIONS  

36

Overview  

36

Pricing And Marketing Of Crude Oil And Natural Gas  

36

Royalties And Incentives  

37

Land Tenure  

37

Environmental Regulation  

38

Worker Safety  

41

RISK FACTORS  

42

MARKET FOR SECURITIES  

54

DIRECTORS AND OFFICERS  

55

Directors Of The Corporation  

55

Officers Of The Corporation  

56

Common Share Ownership  

56

Conflicts Of Interest  

57

Audit & Risk Management Committee Disclosure  

57

LEGAL PROCEEDINGS AND REGULATORY ACTIONS  

57

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS  

57

MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS  

57

INTERESTS OF EXPERTS  

58

TRANSFER AGENT AND REGISTRAR  

58

ADDITIONAL INFORMATION  

58

APPENDIX A – CONTINGENT RESOURCES INFORMATION  

A-1

APPENDIX B – REPORT ON RESERVES DATA AND CONTINGENT RESOURCES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR  

B-1

APPENDIX C – REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE  

C-1

APPENDIX D – AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE PURSUANT TO NATIONAL INSTRUMENT 52-110  

D-1

 

 

 

 

 

 

 

 

i

 

 

Glossary of Terms

 

Unless the context otherwise requires, in this Annual Information Form the following terms and abbreviations have the meanings set forth below. Additional terms relating to oil and natural gas reserves, resources and operations have the meanings set forth under " Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information " in this Annual Information Form and under “Note to Reader Regarding Disclosure of Contingent Resources Information” in Appendix A. All references to “Annual Information Form” include this Annual Information Form of the Corporation dated February 22, 2019 for the year ended December 31, 2018 and all appendices hereto.

 

" ABCA " means the Business Corporations Act (Alberta), as amended

 

" AECO " means the physical storage and trading hub for natural gas on the TransCanada Alberta Transmission System (NOVA) which is the delivery point for the various benchmark Alberta index prices

 

" Bank Credit Facility " means, as at December 31, 2018, the Corporation's $800 million unsecured, covenant‑based revolving credit facility with a syndicate of financial institutions. See “ Description of Capital Structure – Bank Credit Facility ” and " Material Contracts and Documents Affecting the Rights of Securityholders "

 

" COGE Handbook " means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) Canada and the Canadian Institute of Mining, Metallurgy and Petroleum (Petroleum Society), as amended from time to time

 

" Common Shares " means the common shares in the capital of the Corporation

 

" Conversion " means the conversion of Enerplus' business from an income trust structure (with the parent entity being the Fund) to a corporate structure (with the parent entity being the Corporation) effective January 1, 2011 by way of a plan of arrangement under the ABCA, pursuant to which, among other things, the former trust units of the Fund, each of which represented an equal undivided beneficial interest in the Fund, were exchanged on a one‑for‑one basis for Common Shares 

 

" Corporation " means Enerplus Corporation, a corporation amalgamated under the ABCA, and, where the context requires, its subsidiaries, taken as a whole

 

" Credit Facilities " means, collectively, the Bank Credit Facility and the Senior Unsecured Notes. See " Material Contracts and Documents Affecting the Rights of Securityholders "

 

" CSA Notice 51‑324 " means Canadian Securities Administrators Staff Notice 51‑324 (Revised)  – Glossary to NI 51‑101 Standards of Disclosure for Oil and Gas Activities , issued by the Canadian securities regulatory authorities

 

“ESG” means environmental, social and governance

 

" Enerplus " means (i) on and after January 1, 2011, the Corporation and, where the context requires, its subsidiaries, taken as a whole, and (ii) prior to January 1, 2011, the Fund and its subsidiaries, taken as a whole

 

" Enerplus USA " means Enerplus Resources (USA) Corporation, a corporation organized under the laws of Delaware and a wholly‑owned subsidiary of the Corporation

 

“ EOR ” mean enhanced oil recovery, as described in more detail under “ Business of the Corporation – Description of Properties ”

 

“ Financial Statements ” means the audited consolidated financial statements of the Corporation as at December 31, 2018 and 2017 and for three years ended December 2018, 2017 and 2016

 

" Fund " means Enerplus Resources Fund, formerly a trust formed pursuant to the laws of Alberta that was dissolved on January 1, 2011 in connection with the Conversion, and which was the predecessor issuer to the Corporation 

 

“GLJ” means GLJ Petroleum Consultants, independent petroleum consultants

 

" IFRS " means International Financial Reporting Standards, as issued by the International Accounting Standards Board, as amended from time to time

 

" McDaniel " means McDaniel & Associates Consultants Ltd., independent petroleum consultants

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     1

 

 

" McDaniel Reports " means, collectively, the independent engineering evaluations of certain of the Corporation's oil, natural gas liquids and natural gas reserves in Canada and certain of the Corporation's oil, natural gas liquids and natural gas reserves in the United States, prepared by McDaniel effective December 31, 2018, utilizing the average of the commodity price forecasts and inflation rates of  GLJ, McDaniel and Sproule as of January 1, 2019

 

" MD&A " means management's discussion and analysis for the year ended December 31, 2018

 

“ NCIB ” means normal course issuer bid

 

" NI 51‑101 " means National Instrument 51‑101 – Standards of Disclosure for Oil and Gas Activities , adopted by the Canadian securities regulatory authorities

 

" NSAI " means Netherland, Sewell & Associates, Inc., independent petroleum consultants

 

" NSAI Report " means the independent engineering evaluation of the Corporation's shale gas reserves   and contingent resources in the Marcellus properties   prepared by NSAI effective   December 31, 2018, utilizing the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2019

 

" NYSE " means the New York Stock Exchange

 

" SEC " means the United States Securities and Exchange Commission

 

" Senior Unsecured Notes " means, as at December 31, 2018, the US$489 million principal amount and CDN$30 million principal amount of outstanding senior unsecured notes issued by Enerplus. See " Description of Capital Structure – Senior Unsecured Notes " and " Material Contracts and Documents Affecting the Rights of Securityholders "

 

" Shareholder Rights Plan " means the amended and restated shareholder rights plan agreement between the Corporation and Computershare Trust Company of Canada, as rights agent, dated as of May 6, 2016. See “ Description of Capital Structure – Shareholder Rights Plan ” and " Material Contracts and Documents Affecting the Rights of Securityholders "

 

“Sproule” means Sproule Associates Limited, independent petroleum consultants

 

" Tax Act " means the Income Tax Act (Canada), R.S.C. 1985, c.1 (5th Supp.), as amended, including the regulations promulgated thereunder, as amended from time to time

 

" TSX " means the Toronto Stock Exchange

 

" U.S. GAAP " means generally accepted accounting principles in the United States

 

 

2      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

Abbreviations and Conversions

 

In this Annual Information Form, the following abbreviations have the meanings set forth below:

 

 

 

 

API

    

American Petroleum Institute gravity, a measure of how heavy or light a petroleum liquid is compared to water

bbls

 

barrels, with each barrel representing 34.972 imperial gallons or 42 U.S. gallons

bbls/day

 

barrels per day

Bcf

 

one billion cubic feet

BcfGE (1)

 

one billion cubic feet of natural gas equivalent

BOE (1)

 

barrels of oil equivalent

BOE/day (1)

 

barrels of oil equivalent per day

GJ

 

gigajoule; equal to one thousand million joules

Mbbls

 

one thousand barrels

MBOE (1)

 

one thousand barrels of oil equivalent

Mcf

 

one thousand cubic feet

Mcf/day

 

one thousand cubic feet per day

MMBOE (1)

 

one million barrels of oil equivalent

MMbtu

 

one million British Thermal Units

MMcf

 

one million cubic feet

Mt

 

one million tonnes

NAFTA

 

North American Free Trade Agreement

NGLs

 

natural gas liquids

NPV

 

net present value of future net revenue, discounted at 10%

NYMEX

 

the New York Mercantile Exchange

USMCA

WTI

 

United States-Mexico-Canada Agreement

West Texas Intermediate crude oil that serves as the benchmark crude oil for the NYMEX crude oil contract delivered in Cushing, Oklahoma

 

Note: 

(1) The Corporation has adopted the standard of 6 Mcf of natural gas:  1 bbl of oil when converting natural gas to BOEs, MBOEs and MMBOEs, and 1 bbl of oil and NGLs:    6 Mcf of natural gas when converting oil and NGLs to BcfGEs. For further information, see " Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information – Barrels of Oil and Cubic Feet of Gas Equivalent ".

 

In this Annual Information Form, unless otherwise indicated, all dollar amounts are in Canadian dollars and all references to " $ " and " CDN$ " are to Canadian dollars. References to " US$ " are to U.S. dollars. On December 31, 2018, the exchange rate for one U.S. dollar, expressed in Canadian dollars and based upon the closing rate of the Bank of Canada, was CDN$1.3637.

 

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

Mcf

 

cubic metres

 

28.174

cubic metres

 

cubic feet

 

35.494

bbls

 

cubic metres

 

0.159

cubic metres

 

bbls

 

6.293

feet

 

metres

 

0.305

metres

 

feet

 

3.281

miles

 

kilometres

 

1.609

kilometres

 

miles

 

0.621

acres

 

hectares

 

0.4047

hectares

 

acres

 

2.471

 

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     3

 

 

Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information

 

NOTE TO READER REGARDING OIL AND GAS INFORMATION, DEFINITIONS AND NATIONAL INSTRUMENT 51‑101

 

The oil and gas reserves and operational information of the Corporation contained in this Annual Information Form contains the information required to be included in the Statement of Reserves Data and Other Oil and Gas Information pursuant to NI 51‑101 adopted by the Canadian securities regulatory authorities. Readers should also refer to the Report on Reserves Data and Contingent Resources Data by McDaniel and NSAI attached as Appendix B and the Report of Management and Directors on Oil and Gas Disclosure attached hereto as Appendix   C. The effective date for the Statement of Reserves Data and Contingent Resources and Other Oil and Gas Information contained in this Annual Information Form is December 31, 2018 and the preparation dates for such information are February 5, 2019 for the McDaniel Reports and February 7, 2019 for the NSAI Report.

 

Certain of the following definitions and guidelines are contained in the Glossary to NI 51‑101 contained in CSA Notice 51‑324, which incorporates certain definitions from the COGE Handbook. Readers should consult CSA Notice 51‑324 and the COGE Handbook for additional explanation and guidance.

 

For information regarding contingent resources of the Corporation and its presentation, see Appendix A.

 

DISCLOSURE OF RESERVES AND PRODUCTION INFORMATION 

 

Presentation of Information

 

In this Annual Information Form, all oil and natural gas production and realized product prices information is presented on a "company interest" basis (as defined below), unless expressly indicated that it is being presented on a "gross" or "net" basis. "Company interest" means, in relation to the Corporation's interest in production, its working interest (operating or non‑operating) share before deduction of royalties, plus the Corporation's royalty interests in production. "Company interest" is not a term defined or recognized under NI 51‑101 and does not have a standardized meaning under NI 51‑101. Therefore, the "company interest" production of the Corporation may not be comparable to similar measures presented by other issuers, and investors are cautioned that "company interest" production should not be construed as an alternative to "gross" or "net" production calculated in accordance with NI 51‑101.

 

In this Annual Information Form, all crude oil and natural gas information includes tight oil and shale gas, respectively, unless expressly indicated that it is being presented on a separate basis. The Corporation's actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this Annual Information Form. The estimated future net revenue from the production of such oil and natural gas reserves does not necessarily represent the fair market value of such reserves. See " Oil and Natural Gas Reserves – Summary of Reserves " for additional information.  

 

Notice to U.S. Readers

 

Data on oil and natural gas reserves contained in this Annual Information Form has generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. For example, although the SEC now generally permits oil and gas issuers, in their filings with the SEC, to disclose both proved reserves and probable reserves (each as defined in the SEC rules), the SEC definitions of proved reserves and probable reserves may differ from the definitions of "proved reserves" and "probable reserves" under Canadian securities laws. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above with respect to production information, "company interest") volumes, which are volumes prior to deduction of applicable royalties and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments, plus royalty interests. Moreover, in accordance with Canadian disclosure requirements, the Corporation has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC generally requires that reserves estimates be prepared using an unweighted average of the closing prices for the applicable commodity on the first day of each of the twelve months preceding the Corporation's fiscal year‑end, with the option of also disclosing reserves estimates based upon future or other prices. As a consequence of the foregoing, the Corporation's reserves estimates and production volumes may not be comparable to those made by companies utilizing United States reporting and disclosure standards. Additionally, the SEC prohibits disclosure of oil and gas resources in SEC filings, including contingent resources, whereas Canadian securities regulatory authorities allow disclosure of oil and gas resources. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see "Note to Reader Regarding Disclosure of Contingent Resources Information " in Appendix A.

4      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

 

BARRELS OF OIL AND CUBIC FEET OF GAS EQUIVALENT

 

The Corporation has adopted the standard of 6 Mcf of natural gas: 1 bbl of oil when converting natural gas to BOEs, MBOEs and MMBOEs, and 1 bbl of oil and NGLs: 6 Mcf of natural gas when converting oil and NGLs to BcfGEs. BOEs, MBOEs, MMBOEs, and BcfGEs may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

 

INTERESTS IN RESERVES, CONTINGENT RESOURCES, PRODUCTION, WELLS AND PROPERTIES

 

In addition to the terms having defined meanings set forth in CSA Notice 51‑324, the terms set forth below have the following meanings when used in this Annual Information Form:

 

" gross " means:

 

(i)

in relation to the Corporation's interest in production, reserves or contingent resources, its working interest (operating or non‑operating) share before deduction of royalties and without including any royalty interests of the Corporation

 

(ii)

in relation to wells, the total number of wells in which the Corporation has an interest

 

(iii)

in relation to properties, the total area in which the Corporation has an interest

 

" net " means:

 

(i)

in relation to the Corporation's interest in production, reserves or contingent resources, its working interest (operating or non‑operating) share after deduction of royalty obligations, plus the Corporation's royalty interests in production or reserves

 

(ii)

in relation to the Corporation's interest in wells, the number of wells obtained by aggregating the Corporation's working interest in each of its gross wells

 

(iii)

in relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation

 

" working interest " means the percentage of undivided interest held by the Corporation in the oil and/or natural gas or mineral lease granted by the mineral owner (Crown or freehold), which interest gives the Corporation the right to "work" the property (lease) to explore for, develop, produce and market the leased substances.

 

RESERVES CATEGORIES AND LEVELS OF CERTAINTY FOR REPORTED RESERVES 

 

In this Annual Information Form, the following terms have the meaning assigned thereto in CSA Notice 51‑324 and the COGE Handbook:

 

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

 

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

 

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

 

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 estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

ENERPLUS 2018 ANNUAL INFORMATION FORM     5

 

 

 

·

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

 

·

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

 

DEVELOPMENT AND PRODUCTION STATUS 

 

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

 

" 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.

 

·

" 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.

 

·

" 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.

 

" undeveloped reserves " are those reserves that are expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved or probable) to which they are assigned.

 

DESCRIPTION OF PRICE AND COST ASSUMPTIONS

 

" Forecast prices and costs " means future prices and costs that are:

 

(i)

generally accepted as being a reasonable outlook of the future

 

(ii)

if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is 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 rather than the prices or costs referred to in paragraph (i)

 

Presentation of Financial Information

 

The Corporation presents its financial information in accordance with U.S. GAAP. The Corporation continues to qualify as a foreign private issuer for its U.S. securities filings as fewer than 50% of its shareholders resided in the United States as at June 30, 2018. The Corporation is required to reassess this annually, at the end of the second quarter. See " Risk Factors – Government policy and/or regulations and required regulatory approvals and compliance may adversely impact the Corporation's operations and result in increased operating and capital costs ".

 

 

Forward‑Looking Statements and Information

 

This Annual Information Form contains certain forward‑looking statements and forward‑looking information (collectively, "forward‑looking information") within the meaning of applicable securities laws which are based on the Corporation's current internal expectations, estimates, projections, assumptions, and beliefs. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "intend", "guidance", "objective", "strategy", "should", "believe" and similar expressions are intended to identify forward‑looking information. These statements are not guarantees of future performance, and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward‑looking information. The Corporation believes the expectations reflected in such forward‑looking information are reasonable but no assurance can be given that these expectations will prove to be correct, and such forward‑looking information included in this Annual Information Form should not be relied upon unduly. Such forward‑looking information speaks only as of the date of this Annual Information Form and the Corporation does not undertake any obligation to publicly update or revise any forward‑looking information, except as required by applicable laws.

 

6      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

In particular, this Annual Information Form contains forward‑looking information pertaining to the following:

 

·

the quantity of, and future net revenues from, the Corporation's reserves and/or contingent resources

 

·

crude oil, NGLs and natural gas production levels

 

·

commodity prices, foreign currency exchange rates and interest rates

 

·

operating expenditures

 

·

current capital expenditure programs, drilling programs, development plans and other future expenditures, including the planned allocation of capital expenditures among the Corporation's properties and the sources of funding for such expenditures

 

·

supply and demand for oil, NGLs and natural gas

 

·

the Corporation's business strategy, including its asset and operational focus

 

·

future acquisitions and divestments, and future growth potential

 

·

expectations regarding the Corporation's ability to raise capital and to continually add to reserves and/or resources through acquisitions and development

 

·

schedules for and timing of certain projects and the Corporation's strategy for growth

 

·

the Corporation's future operating and financial results

 

·

the Corporation's tax pools and the time at which the Corporation may incur certain income or other taxes

 

·

treatment of, and compliance by the Corporation with, governmental and other regulatory regimes and tax, environmental and other laws

 

·

future dividends that may be paid by the Corporation

 

The forward‑looking information contained in this Annual Information Form reflects several material factors and expectations and assumptions made by the Corporation including, without limitation, that: the Corporation's current commodity price and other cost assumptions will generally be accurate; the Corporation will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; the Corporation's conduct and results of operations will be consistent with its expectations; the Corporation and its industry partners will have the ability to develop the Corporation's oil and gas properties in the manner currently contemplated; a lack of infrastructure does not result in the Corporation or a third party curtailing its production and/or receiving reductions to its realized prices; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; the estimates of the Corporation's reserves and resources volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; and there will be sufficient availability of services and labour to conduct the Corporation's operations as planned.

 

The Corporation’s current 2019 capital expenditure budget contained in this Annual Information Form assumes:  WTI price of between US$50/bbl and US$55/bbl, NYMEX natural gas price of US$3.00/Mcf, and a foreign exchange rate of USD/CDN 1.32.

 

The Corporation believes the material factors, expectations and assumptions reflected in the forward‑looking information are reasonable at this time but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

 

The Corporation's actual results could differ materially from those anticipated in this forward‑looking information as a result of both known and unknown risks, including the risk factors set forth under " Risk Factors " in this Annual Information Form and risks relating to:

 

·

ongoing volatility in market prices for crude oil, NGLs and natural gas, including changes in supply or demand for those products

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     7

 

 

·

actions by governmental or regulatory authorities, including mandated production curtailments or different interpretations of applicable laws, treaties or administrative positions, as well as changes in income tax laws or changes in royalty regimes and incentive programs relating to the oil and gas industry

 

·

unanticipated operating results, including changes or fluctuations in crude oil, NGLs and natural gas production levels

 

·

changes in foreign currency exchange rates, including Canadian currency compared to U.S., and its impact on the Corporation’s operations and financial condition

 

·

changes in interest rates

 

·

changes in development plans by the Corporation or third-party operators

 

·

the ability of the Corporation to comply with debt covenants under the Credit Facilities

 

·

the ability of the Corporation to access required capital

 

·

changes in capital and other expenditure requirements and debt service requirements

 

·

liabilities and unexpected events inherent in oil and gas operations, including geological, technical, drilling and processing risks, as well as unforeseen title defects or litigation

 

·

actions of and reliance on industry partners

 

·

uncertainties associated with estimating reserves and resources

 

·

competition for, among other things, capital, acquisitions of reserves and resources, undeveloped lands, access to services, third party processing capacity and skilled personnel

 

·

incorrect assessments of the value of acquisitions or divestments, or the failure to complete divestments

 

·

constraints on, or the unavailability of, adequate infrastructure, including pipeline and other transportation capacity, to deliver the Corporation's production to market, whether in the control of the Corporation or not

 

·

the Corporation's success at the acquisition, exploitation and development of reserves and resources

 

·

changes in general economic, market (including credit market) and business conditions in North America and worldwide

 

·

changes in tax, environmental, regulatory, or other legislation applicable to the Corporation and its operations, and the Corporation's ability to comply with current and future environmental legislation and regulations and other laws and regulations,  including those impacting financial institutions, that could limit commodity market liquidity

 

Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in the Corporation's MD&A, which are available on the internet under the Corporation's SEDAR profile at  www.sedar.com ,  the Corporation's EDGAR profile at  www.sec.gov as part of the annual report on Form 40‑F filed with the SEC (together with this Annual Information Form), and on the Corporation's website at  www.enerplus.com . Readers are also referred to the risk factors described in this Annual Information Form under " Risk Factors " and in other documents the Corporation files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the Corporation or electronically on the internet on the Corporation's SEDAR profile at  www.sedar.com , on the Corporation's EDGAR profile at  www.sec.gov and on the Corporation's website at  www.enerplus.com .

 

8      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

Corporate Structure

 

ENERPLUS CORPORATION

 

The Corporation was incorporated on August 12, 2010 under the ABCA for the purposes of participating in the Conversion under which the business of the Fund, as the Corporation's predecessor, was transitioned to the Corporation. As part of the plan of arrangement under the ABCA pursuant to which the Conversion was effected, the Corporation was amalgamated with several other former direct and indirect subsidiaries of the Fund on January 1, 2011 and continued as the Corporation. Prior to the Conversion, the business of the Corporation was carried on by the Fund and its subsidiaries as an income trust since 1986.

 

Effective May 11, 2012, the Corporation amended and restated its Articles in connection with the implementation of a stock dividend program. See " Description of Capital Structure – Common Shares " and " Dividends – Stock Dividend Program ". 

 

The head, principal and registered office of the Corporation is located at The Dome Tower, 3000, 333 ‑ 7th Avenue S.W., Calgary, Alberta, T2P 2Z1. The Corporation also has a U.S. office located at Suite 2200, 950 ‑ 17th Street, Denver, Colorado, 80202‑2805. The Common Shares are currently traded on the TSX and the NYSE under the symbol "ERF".

 

MATERIAL SUBSIDIARIES

 

As of December 31, 2018, Enerplus USA was the only material subsidiary of Enerplus Corporation. All of the issued and outstanding securities of Enerplus USA are owned by the Corporation.

 

ORGANIZATIONAL STRUCTURE

 

The simplified organizational structure of Enerplus Corporation and its material subsidiary as of December 31, 2018 is set forth below.

PICTURE 1

 

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     9

 

 

General Development of the Business

 

DEVELOPMENTS IN THE PAST THREE YEARS

 

Developments in 2016

 

SENIOR NOTES REPURCHASE

 

The Corporation repurchased a total of US$267 million aggregate principal amount of the Senior Unsecured Notes between 90% of par and par during the first half of 2016, resulting in a gain of $19.3 million being recorded for the year. The repurchases were funded through asset divestment proceeds and the Bank Credit Facility.

 

FINANCING

 

On May 31, 2016, the Corporation completed a bought-deal offering of 33,350,000 Common Shares (including 4,300,000 Common Shares issued pursuant to the exercise in full of the over-allotment option granted to the underwriters), at $6.90 per Common Share, for total proceeds of $230,115,000. The net proceeds from the offering were used by the Corporation to reduce indebtedness under the Bank Credit Facility, to fund its capital expenditures, and for general corporate purposes.

 

SALE OF ASSETS

 

In 2016, the Corporation realized proceeds of approximately $670 million from the divestment of certain of its non-strategic crude oil and natural gas assets. These divestments included approximately 13,500   BOE/day of production, in aggregate, from crude oil and natural gas assets in Canada, as well as certain non-operated North Dakota assets in the United States. The proceeds from the Corporation's divestment activities were used to fund the Corporation's capital program, repurchase a portion of its Senior Unsecured Notes, as described above, and to reduce amounts outstanding under the Bank Credit Facility.

 

Developments in 2017

 

SALE OF ASSETS

 

In 2017, the Corporation realized proceeds of approximately $56 million, as well as a reduction in its asset retirement obligations of $72 million on a discounted basis (see Note 8 to the Financial Statements), from the divestment of certain of its crude oil and natural gas assets in Canada. These divestments included associated production of approximately 7,700 BOE/day, in aggregate,  and reduced the Corporation’s well count by 3,200 wells.  The proceeds from the Corporation's divestment activities were used to repay amounts outstanding on its Credit Facilities and general corporate purposes.

 

Developments in 2018

 

NORMAL COURSE ISSUER BID

 

During 2018, the Corporation repurchased an aggregate of 5.9 million Common Shares for $79.0 million, pursuant to its NCIB which will expire on March 25, 2019. As of February 20, 2019, an additional   586,953 Common Shares have been repurchased under the NCIB in 2019.

 

10      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

Business of the Corporation 

 

OVERVIEW

 

The Corporation's oil and natural gas property interests are located in the United States, primarily in North Dakota, Montana, Colorado and Pennsylvania, as well as in western Canada in the provinces of Alberta, British Columbia and Saskatchewan. Capital spending on these assets in 2018 totaled $593.9 million with over 88% of this focused on the Corporation’s crude oil assets in North Dakota and crude oil properties in Canada.

 

In the United States, capital spending on the Bakken and Three Forks assets in North Dakota totaled approximately  $434.7 million during 2018. In Canada, capital spending of $46.3 million in 2018 was directed to ongoing waterflood implementation at Ante Creek, Alberta, along with drilling and waterflood optimization activities for the Corporation’s other waterflood assets. Capital spending on the Corporation’s natural gas interests in northeast Pennsylvania was $66.2 million. Canadian natural gas properties received a minimal amount of capital during 2018. 

 

In 2018,  the Corporation acquired property and land for a total of $25.8 million, including land acquisitions in Colorado and a property swap in North Dakota. In addition, the Corporation received net divestment consideration of $6.9 million primarily related to an acreage swap in North Dakota.

 

The Corporation's major producing properties generally have related field facilities and infrastructure to accommodate its production. Production volumes for the year ended December 31, 2018 from the Corporation's properties consisted of 54% crude oil and NGLs and 46% natural gas, on a BOE basis. The Corporation's 2018 average daily production was 93,216 BOE/day, comprised of 45,424 bbls/day of crude oil, 4,486 bbls/day of NGLs and 259,837 Mcf/day of natural gas, an increase of approximately 10% compared to 2017 average daily production of 84,711 BOE/day, comprised of 36,935 bbls/day of crude oil, 3,858 bbls/day of NGLs and 263,506 Mcf/day of natural gas. The increase in average daily production in 2018 compared to 2017 is largely attributable to the strong well performance and growth in U.S. production, where the majority of 2018 capital was invested. The Corporation’s 2018 production in the United States was 84% of its total production, with the remaining 16% from Canada. Approximately 57% of the Corporation’s 2018 production was operated by the Corporation, with the remainder operated by industry partners.

 

As at December 31, 2018, the oil and natural gas property interests held by the Corporation were estimated to contain total proved plus probable gross reserves of approximately 12.7 MMbbls of light and medium crude oil, 28.4 MMbbls of heavy crude oil, 167.2 MMbbls of tight oil, 21.1 MMbbls of NGLs, 41.1 Bcf of conventional natural gas and 1,149.5 Bcf of shale gas, for a total of 427.7 MMBOE. The Corporation's proved reserves represented approximately 70% of total proved plus probable reserves, with approximately 54% of the Corporation's proved plus probable reserves weighted to crude oil and NGLs. See " Oil and Natural Gas Reserves ".

 

Unless otherwise noted: (i) all production and operational information in this Annual Information Form is presented as at or, where applicable, for the year ended, December 31, 2018, (ii) all production information represents the Corporation's company interest in production from these properties, which includes overriding royalty interests of the Corporation but is calculated before deduction of royalty interests owned by others, and (iii) all references to reserves volumes represent gross reserves using forecast prices and costs. See " Presentation of Oil and Gas Reserves, Contingent Resources,   and Production Information ".

 

SUMMARY OF PRINCIPAL PRODUCTION LOCATIONS 

 

During the year ended December 31, 2018, on a BOE basis, 84% of the Corporation's production was derived from the United States (51% from North Dakota, 44%   from Pennsylvania, 4% from Montana, and 1% from Colorado) and 16%   from Canada (65% from Alberta, 22% from Saskatchewan and 13% from British Columbia). The following table describes the average daily production from the Corporation's principal producing properties and regions during the year ended December 31, 2018.

ENERPLUS 2018 ANNUAL INFORMATION FORM     11

 

 

 

2018 Average Daily Production from Principal Properties and Regions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Products

 

 

 

 

Crude Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional

 

 

 

 

 

 

Light and

 

 

 

 

 

 

 

Natural

 

Shale

 

 

Property/Region

    

Medium

    

Heavy

    

Tight

    

NGLs

    

Gas

    

Gas

    

Total

 

 

(bbls/day)

 

(bbls/day)

 

(bbls/day)

 

(bbls/day)

 

(Mcf/day)

 

(Mcf/day)

 

(BOE/day)

United States

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fort Berthold, North Dakota

 

 -

 

 -

 

33,090

 

3,415

 

 -

 

18,918

 

39,659

Marcellus, Pennsylvania

 

 -

 

 -

 

 -

 

 -

 

 -

 

207,993

 

34,666

Sleeping Giant, Montana

 

 -

 

 -

 

2,417

 

 1

 

 -

 

5,382

 

3,315

DJ Basin, Colorado

 

 -

 

 -

 

631

 

 -

 

 -

 

 -

 

631

Other U.S.

 

 -

 

 -

 

 4

 

 6

 

 -

 

47

 

16

Total United States

 

 -

 

 -

 

36,142

 

3,422

 

 -

 

232,340

 

78,287

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Freda Lake/Ratcliffe, Saskatchewan

 

2,902

 

-

 

 -

 

 -

 

 -

 

 -

 

2,902

Medicine Hat Glauc C, Alberta

 

 -

 

2,736

 

 -

 

 -

 

271

 

 -

 

2,781

Tommy Lakes, British Columbia

 

 7

 

 -

 

 -

 

188

 

10,553

 

 -

 

1,954

Giltedge, Alberta

 

 -

 

1,473

 

 -

 

 -

 

 -

 

 -

 

1,473

Ante Creek, Alberta

 

805

 

 -

 

 -

 

75

 

2,459

 

 -

 

1,289

Cadogan, Alberta

 

 -

 

729

 

 -

 

 6

 

168

 

 -

 

763

Pine Creek, Alberta

 

 1

 

 -

 

 -

 

118

 

2,702

 

 -

 

570

Willesden Green, Alberta

 

 1

 

 -

 

 -

 

178

 

1,770

 

 -

 

474

Other Canada

 

571

 

57

 

 -

 

499

 

9,236

 

338

 

2,723

Total Canada

 

4,287

 

4,995

 

 -

 

1,064

 

27,159

 

338

 

14,929

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

4,287

 

4,995

 

36,142

 

4,486

 

27,159

 

232,678

 

93,216

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For additional information on the Corporation's oil and natural gas properties, see " Description of Properties ".

 

CAPITAL EXPENDITURES AND COSTS INCURRED

 

The Corporation invested $593.9 million in its capital program during 2018,  with 88% directed to oil-related projects. This increase of 30%  compared to 2017 spending of $458.0 million was planned, primarily due to higher cash flow expectations from structural cost reductions in the business and improvements in the Corporation’s realized U.S. sales price differentials during 2018.  Capital investment during 2018 was focused on the Corporation’s U.S. North Dakota Bakken crude oil property (with investment of approximately $434.7   million), its U.S. Marcellus assets (with investment of approximately $66.2   million), its Canadian crude oil properties (with investment of approximately $46.3   million), and its Denver-Julesburg (“ DJ Basin ”) assets in Colorado where it invested $39.7 million on  the drilling and completion of four delineation wells.

 

In the financial year ended December 31, 2018, the Corporation made the following expenditures in the categories noted, as prescribed by NI 51‑101:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property Acquisition

 

 

 

 

 

 

 

 

Costs

 

Exploration

 

Development

 

    

Proved

    

Unproved

    

Costs

    

Costs

 

 

($ in millions)

United States

 

$

6.1

 

$

15.6

 

$

1.0

 

$

539.6

Canada

 

 

-

 

 

3.9

 

 

0.6

 

 

52.7

Total

 

$

6.1

 

$

19.5

 

$

1.6

 

$

592.3

 

Based on a  budgeted commodity price of between US$50 and US$55 per barrel for crude oil and US$3.00 NYMEX for natural gas,  the Corporation expects its 2019 exploration and development capital spending to be between $565 million and $635 million, with approximately 93% of this spending projected to be invested in the Corporation's U.S. and Canadian crude oil projects. The Corporation currently expects to invest 80% of its planned 2019 capital spending on its Fort Berthold property in North Dakota, 5% in the DJ Basin of Colorado, and 7.5% on its Canadian crude oil properties.  The Corporation intends to spend the remaining 7.5% of its 2019 capital on its non-operated Marcellus natural gas properties in the northeast region of Pennsylvania.

 

12      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

The Corporation intends to finance its 2019 capital expenditure program with cash,  internally generated cash flow and/or debt. The Corporation will review its 2019 capital investment plans throughout the year in the context of prevailing economic conditions, commodity prices and potential acquisitions and divestments, making adjustments as it deems necessary. See “ Forward-Looking Statements and Information ”. 

 

For further information regarding the Corporation's properties and its 2018 exploration and development activities, see " Description of Properties ",  below.

 

EXPLORATION AND DEVELOPMENT ACTIVITIES

 

The following table summarizes the number and type of wells that the Corporation drilled or participated in the drilling of for the year ended December 31, 2018, in each of Canada and the United States. Wells have been classified in accordance with the definitions of such terms in NI 51‑101.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

Canada

 

 

 

Development Wells

 

Exploratory Wells

 

Development Wells

 

Exploratory Wells

Category of Well

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

Crude oil wells

 

60

 

47

 

 -

 

 -

 

21

 

 6

 

 -

 

 -

Natural gas wells

 

57

 

 8

 

 -

 

 -

 

 1

 

 -

 

 -

 

 -

Service wells

 

 -

 

 -

 

 -

 

 -

 

 9

 

 2

 

 -

 

 -

Dry and abandoned wells

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

Total

 

117

 

55

 

-

 

-

 

31

 

8

 

-

 

-

 

For a description of the Corporation’s 2019 development plans and the anticipated sources of funding these plans, see " Capital Expenditures and Costs Incurred ", above.

 

OIL AND NATURAL GAS WELLS AND UNPROVED PROPERTIES

 

The following table summarizes, at December 31, 2018, the Corporation's interests in producing wells and in non‑producing wells which were not producing but which may be capable of production, along with the Corporation's interests in unproved properties (as defined in NI 51‑101). Although many wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the proportion of oil or natural gas production that constitutes the majority of production from that well.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Producing Wells

 

Non-Producing Wells

 

Unproved Properties

 

 

Oil

 

Natural Gas

 

Oil

 

Natural Gas

 

(acres)

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

United States

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Colorado

 

 5

 

 5

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

36,697

 

33,863

Montana

 

243

 

164

 

 -

 

 -

 

23

 

18

 

 -

 

 -

 

-

 

-

North Dakota

 

246

 

194

 

 -

 

 -

 

20

 

15

 

 -

 

 -

 

-

 

-

Pennsylvania

 

 -

 

 -

 

853

 

91

 

 -

 

 -

 

72

 

12

 

33,124

 

9,556

Canada

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Alberta

 

545

 

231

 

274

 

62

 

348

 

92

 

151

 

44

 

149,660

 

104,567

British Columbia

 

 -

 

 -

 

154

 

145

 

 -

 

 -

 

19

 

 9

 

27,292

 

22,390

Saskatchewan

 

629

 

98

 

80

 

23

 

288

 

25

 

157

 

148

 

22,215

 

16,126

Total

 

1,668

 

692

 

1,361

 

321

 

679

 

151

 

399

 

212

 

268,988

 

186,502

 

The Corporation expects its rights to explore, develop and exploit on approximately 27,624 net acres of unproved properties in Canada to expire, in the ordinary course, prior to December 31, 2019.  The Corporation has no material work commitments on such properties and, where the Corporation determines appropriate, it can extend expiring leases by either making the necessary applications to extend or performing the necessary work.

 

For any properties with no reserves or on unproved lands, the Corporation does not have any significant abandonment and reclamation costs, unusually high expected development costs or operating costs, or contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations. Operating expenditures and abandonment and reclamation costs for all properties with no reserves or on unproved lands are included in the Corporation’s MD&A and asset retirement disclosures in the Financial Statements.

ENERPLUS 2018 ANNUAL INFORMATION FORM     13

 

 

DESCRIPTION OF PROPERTIES

 

Outlined below is a description of the Corporation's U.S. and Canadian crude oil and natural gas properties and assets.

 

For additional information on contingent resources associated with certain of the Corporation’s United States and Canadian crude oil and natural gas properties, including estimated volumes of economic contingent resources, see “ Appendix A – Contingent Resources Information” .

 

U.S. Crude Oil Properties

 

OVERVIEW

 

The Corporation’s primary U.S. crude oil properties are located in the Fort Berthold region of North Dakota, the Wattenberg Field of the DJ Basin of Colorado and in Richland County, Montana. The Corporation spent $474.4 million on its U.S. crude oil assets in 2018.

 

The Corporation has approximately 65,600   net acres of land in Fort Berthold, primarily in Dunn and McKenzie Counties and, on a production basis, operates approximately 93% of its Fort Berthold asset. The Corporation’s Fort Berthold property produces a light sweet crude oil (42° API), with some associated natural gas and NGLs, from both the Bakken and Three Forks formations. Fort Berthold production averaged 39,659 BOE/day in 2018. During 2018, the Corporation spent  approximately $434.7   million on its operated and non-operated assets in North Dakota, focusing on the execution of its liquids growth plans. During 2018, the Corporation drilled 43.0   net horizontal wells in the Fort Berthold region, targeting both the Bakken and Three Forks formations (consisting of 5.0 net short lateral wells and 38.0 net long lateral wells), with 35.5 net wells brought on-stream. At the end of 2018, the Corporation had 14.5 net drilled uncompleted wells.

 

The Corporation holds approximately 39,000 net acres (held through leasing and farm-ins) in the DJ Basin of Colorado (northwest Weld County, Wattenberg Field). The Wattenberg Field has been producing since the 1970s and is characterized as having high recoveries and initial production rates, long reserves life and multiple stacked producing horizons. Capital investment in the DJ Basin in 2018 was $39.7 million and focused on the drilling and completion of four wells, three of which targeted the Codell formation and one the Niobrara formation. Production for the fourth quarter of 2018 was approximately 1,203 BOE/day, or approximately 631 BOE/day on an annual average basis.

 

The Corporation also has working interests in Sleeping Giant, a mature, light oil property located in the Elm Coulee Field in Richland County, Montana. Sleeping Giant produced approximately 3,315   BOE/day on average from the Bakken formation in 2018.  

 

Overall, the Corporation's U.S. crude oil properties produced an average of approximately 43,605 BOE/day in 2018, up 36% from 2017 due to higher capital spending in North Dakota. On a BOE basis, this represents 47% of the Corporation's 2018 average daily production.

 

Approximately 35.1   MMBOE of proved plus probable reserves were added at Fort Berthold during 2018, including technical revisions and economic factors. After adjusting for 2018 production of 14.5 MMBOE, total proved plus probable reserves associated with this property as at December 31, 2018 were 191.1 MMBOE, 12% higher than at December 31, 2017.

 

The Corporation had 206.3 MMBOE of proved plus probable reserves associated with its U.S. crude oil assets at December 31, 2018, representing approximately 48% of its total proved plus probable reserves.

 

The Corporation has entered into long‑term agreements for the gathering, dehydration, processing, compression and transportation of the Corporation's share of crude oil, natural gas and NGL production from its North Dakota and Montana properties. These agreements are intended to provide the Corporation with cost certainty, and access to the  U.S. Gulf Coast, where it can further access export crude oil markets. See “ Marketing Arrangements and Forward Contracts” for further information.

 

U.S. Natural Gas Properties

 

OVERVIEW

 

The Corporation's U.S. natural gas properties consist entirely of its non‑operated Marcellus shale gas interests located in northeastern Pennsylvania, where the Corporation holds an interest in about 34,500 net acres. The Corporation's Marcellus shale gas production averaged 207,993 Mcf/day in 2018, representing approximately 37% of the Corporation's total average daily production.  

 

14      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

In 2018, approximately $66.2 million was invested in the Corporation's Marcellus interests. The Corporation participated in the drilling of a total of 8.3 net wells, a total of 6.7 net wells were brought on-stream, and 6.0 net wells were waiting on completion or tie‑in.

 

Proved plus probable Marcellus shale gas reserves were 1,029.2 Bcf as at December 31, 2018, an increase of 111.5 Bcf from 2017, and represented approximately 40% of the Corporation's total proved plus probable reserves.

 

The Corporation has entered into long‑term agreements for the gathering, dehydration, compression and transportation of the Corporation's share of production from its Marcellus properties. These agreements are intended to provide the Corporation with cost certainty and access to the northeastern United States and broader U.S. natural gas markets through connections with major interstate pipelines. See “ Marketing Arrangements and Forward Contracts” for further information.

 

 

Canadian Crude Oil Properties

 

OVERVIEW

 

Production from the Corporation’s Canadian crude oil properties comes primarily from mature, low decline assets under waterflood and EOR techniques. Primary waterfloods inject water into the formation using injection wells to supplement reservoir pressure and provide a drive mechanism to move additional oil to producing wells. Pressure maintenance and the production of oil from water injection can result in a more predictable production profile and more stable declines, as well as higher recovery of reserves. Infill drilling, well injection optimization and EOR techniques are effective methods of improving recovery of reserves even further. These properties have associated crude oil production facilities for emulsion treatment and injection or water disposal.

 

The Canadian crude oil properties provide a stable production base and cash flow to support the Corporation’s investment in growth plays, as well as its dividend. Total Canadian crude oil properties production averaged 9,897   BOE/day during 2018, or 11% of the Corporation’s total average daily production.  Capital investment in the Canadian crude oil properties was focused on its waterflood assets in Alberta, including water injection and optimization activities at Ante Creek and drilling activity in Medicine Hat, as well as drilling and on-streams in southeast Saskatchewan. On a production basis, the Corporation operated approximately 97% of its Canadian crude oil properties.

 

In 2018, the Corporation invested approximately $46.3 million in its Canadian crude oil properties, which was directed to drilling,  completions, waterflood optimization and advancement, along with facility enhancements to support future activities. The Corporation drilled and completed 4.8 net crude oil wells and 2.2 net water injection wells in its Canadian crude oil properties during 2018. 

 

Effectively all of the 41.8 MMBOE, or approximately 10% of the Corporation’s total proved plus probable reserves on a BOE basis are associated with Canadian crude oil properties using waterflood or EOR techniques at December 31, 2018. 

 

Canadian Natural Gas Properties

 

OVERVIEW

 

The Corporation's primary Canadian natural gas properties are located in Alberta and British Columbia. During 2018,  production from the Corporation's Canadian natural gas properties averaged 34,326 Mcf/day. The Corporation's largest producing Canadian natural gas property in 2018  was Tommy Lakes, located in British Columbia.

 

The Corporation spent approximately $7 million of capital on its non-operated Canadian natural gas assets at Ferrier and Willesden Green during 2018.

 

Proved plus probable reserves for Canadian natural gas properties totaled 48.3 BcfGE as at December 31, 2018, representing approximately 2% of the Corporation's total proved plus probable reserves on a BOE basis.

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     15

 

 

QUARTERLY PRODUCTION HISTORY

 

The following table sets forth the Corporation's average daily production volumes, on a company interest basis, by product type, for each fiscal quarter in 2018 and for the entire year, separately for production in Canada and the United States, and in total.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

 

    

First

    

Second

    

Third

    

Fourth

    

 

Country and Product Type

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Annual

United States

 

 

 

 

 

 

 

 

 

 

Light and medium oil (bbls/day)

 

 -

 

 -

 

 -

 

 -

 

 -

Heavy oil (bbls/day)

 

 -

 

 -

 

 -

 

 -

 

 -

Tight oil (bbls/day)

 

27,930

 

36,030

 

39,697

 

40,731

 

36,142

Total crude oil (bbls/day)

 

27,930

 

36,030

 

39,697

 

40,731

 

36,142

Natural gas liquids (bbls/day)

 

2,838

 

3,753

 

3,561

 

3,527

 

3,422

Total liquids (bbls/day)

 

30,768

 

39,783

 

43,258

 

44,258

 

39,564

Conventional natural gas (Mcf/day)

 

 -

 

 -

 

 -

 

 -

 

 -

Shale gas (Mcf/day)

 

228,178

 

227,844

 

236,105

 

237,096

 

232,340

Total United States (BOE/day)

 

68,798

 

77,757

 

82,608

 

83,774

 

78,287

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

 

 

Light and medium oil (bbls/day)

 

4,255

 

4,332

 

4,266

 

4,293

 

4,287

Heavy oil (bbls/day)

 

5,258

 

4,880

 

4,904

 

4,944

 

4,995

Tight oil (bbls/day)

 

 -

 

 -

 

 -

 

 -

 

 -

Total crude oil (bbls/day)

 

9,513

 

9,212

 

9,170

 

9,237

 

9,282

Natural gas liquids (bbls/day)

 

1,247

 

1,055

 

1,002

 

956

 

1,064

Total liquids (bbls/day)

 

10,760

 

10,267

 

10,172

 

10,193

 

10,346

Conventional natural gas (Mcf/day)

 

32,691

 

28,750

 

24,226

 

23,105

 

27,159

Shale gas (Mcf/day)

 

441

 

401

 

260

 

252

 

338

Total Canada (BOE/day)

 

16,282

 

15,126

 

14,253

 

14,086

 

14,929

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

Light and medium oil (bbls/day)

 

4,255

 

4,332

 

4,266

 

4,293

 

4,287

Heavy oil (bbls/day)

 

5,258

 

4,880

 

4,904

 

4,944

 

4,995

Tight oil (bbls/day)

 

27,930

 

36,030

 

39,697

 

40,731

 

36,142

Total crude oil (bbls/day)

 

37,443

 

45,242

 

48,867

 

49,968

 

45,424

Natural gas liquids (bbls/day)

 

4,085

 

4,808

 

4,563

 

4,483

 

4,486

Total liquids (bbls/day)

 

41,528

 

50,050

 

53,430

 

54,451

 

49,910

Conventional natural gas (Mcf/day)

 

32,691

 

28,750

 

24,226

 

23,105

 

27,159

Shale gas (Mcf/day)

 

228,619

 

228,245

 

236,365

 

237,348

 

232,678

Total (BOE/day)

 

85,080

 

92,883

 

96,861

 

97,860

 

93,216

 

 

16      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

QUARTERLY NETBACK HISTORY

 

The following tables set forth the Corporation's average netbacks received for each fiscal quarter in 2018 and for the entire year, separately for production in Canada and the United States. Netbacks are calculated on the basis of prices received, which are net of transportation costs but before the effects of commodity derivative instruments, less related royalties and production costs. For multiple product wells, production costs are entirely attributed to that well's principal product type. As a result, no production costs are attributed to the Corporation's NGLs production as those costs have been attributed to the applicable wells' principal product type.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

    

First

    

Second

    

Third

    

Fourth

    

 

Light and Medium Crude Oil ($ per bbl)

 

 Quarter

 

 Quarter

 

 Quarter

 

 Quarter

 

Annual

Canada

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales price (1)

 

$

62.23

 

$

73.59

 

$

74.09

 

$

43.66

 

$

63.38

Transportation

 

 

(1.82)

 

 

(1.76)

 

 

(1.70)

 

 

(1.64)

 

 

(1.73)

Royalties (2)

 

 

(15.44)

 

 

(16.77)

 

 

(18.34)

 

 

(10.94)

 

 

(15.36)

Production costs (3)

 

 

(14.36)

 

 

(10.82)

 

 

(17.17)

 

 

(13.82)

 

 

(14.04)

Netback

 

$

30.61

 

$

44.24

 

$

36.88

 

$

17.26

 

$

32.25

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

 

First

 

Second

 

Third

 

Fourth

 

 

Heavy Oil ($ per bbl)

    

Quarter

    

Quarter

    

Quarter

    

Quarter

    

Annual

Canada

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales price (1)

 

$

45.21

 

$

60.36

 

$

64.79

 

$

25.16

 

$

48.75

Transportation

 

 

(1.71)

 

 

(2.05)

 

 

(1.72)

 

 

(1.60)

 

 

(1.77)

Royalties (2)

 

 

(8.73)

 

 

(11.07)

 

 

(16.08)

 

 

(4.06)

 

 

(9.95)

Production costs (3)

 

 

(11.82)

 

 

(15.91)

 

 

(15.18)

 

 

(16.78)

 

 

(14.89)

Netback

 

$

22.95

 

$

31.33

 

$

31.81

 

$

2.72

 

$

22.14

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

 

First

 

Second

 

Third

 

Fourth

 

 

Tight Oil ($ per bbl)

    

Quarter

    

Quarter

    

Quarter

    

Quarter

    

Annual

United States

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales price (1)

 

$

75.41

 

$

83.41

 

$

87.42

 

$

71.07

 

$

79.49

Transportation

 

 

(2.42)

 

 

(2.83)

 

 

(3.01)

 

 

(3.06)

 

 

(2.87)

Royalties (2)

 

 

(21.01)

 

 

(23.31)

 

 

(24.25)

 

 

(20.33)

 

 

(22.28)

Production costs (3)

 

 

(12.61)

 

 

(12.82)

 

 

(10.79)

 

 

(11.42)

 

 

(11.82)

Netback

 

$

39.37

 

$

44.45

 

$

49.37

 

$

36.26

 

$

42.52

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

 

First

 

Second

 

Third

 

Fourth

 

 

Natural Gas Liquids ($ per bbl)

    

Quarter

    

Quarter

    

Quarter

    

Quarter

    

Annual

United States

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales price (1)

 

$

20.66

 

$

27.18

 

$

20.47

 

$

23.20

 

$

23.05

Transportation

 

 

(1.82)

 

 

(2.00)

 

 

(1.90)

 

 

(1.85)

 

 

(1.90)

Royalties (2)

 

 

(3.34)

 

 

(5.15)

 

 

(3.59)

 

 

(4.68)

 

 

(4.25)

Production costs (3)

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

 -

Netback

 

$

15.50

 

$

20.03

 

$

14.98

 

$

16.67

 

$

16.90

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

                

 

              

 

               

 

               

 

 

 

Sales price (1)

 

$

45.11

 

$

50.20

 

$

45.44

 

$

39.69

 

$

45.22

Transportation

 

 

(1.27)

 

 

(1.97)

 

 

(1.35)

 

 

(1.37)

 

 

(1.48)

Royalties (2)

 

 

(8.93)

 

 

(10.91)

 

 

(7.86)

 

 

(8.10)

 

 

(8.99)

Production costs (3)

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

 -

Netback

 

$

34.91

 

$

37.32

 

$

36.23

 

$

30.22

 

$

34.75

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     17

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

 

First

 

Second

 

Third

 

Fourth

 

 

Conventional Natural Gas ($ per Mcf)

    

Quarter

    

Quarter

    

Quarter

    

Quarter

    

Annual

Canada

 

                

 

               

 

               

 

                

 

 

 

Sales price (1)

 

$

3.12

 

$

2.09

 

$

2.80

 

$

3.76

 

$

2.91

Transportation

 

 

(0.46)

 

 

(0.39)

 

 

(0.60)

 

 

(0.51)

 

 

(0.48)

Royalties (2)

 

 

0.12

 

 

0.41

 

 

0.25

 

 

0.49

 

 

0.30

Production costs (3)

 

 

(3.19)

 

 

(2.37)

 

 

(2.48)

 

 

(2.19)

 

 

(2.60)

Netback

 

$

(0.41)

 

$

(0.26)

 

$

(0.03)

 

$

1.55

 

$

0.13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

 

First

 

Second

 

Third

 

Fourth

 

 

Shale Gas ($ per Mcf)

    

Quarter

    

Quarter

    

Quarter

    

Quarter

    

Annual

United States

 

                

 

               

 

               

 

                

 

 

 

Sales price (1)

 

$

3.56

 

$

2.76

 

$

3.27

 

$

4.33

 

$

3.49

Transportation

 

 

(0.84)

 

 

(0.84)

 

 

(0.85)

 

 

(0.86)

 

 

(0.85)

Royalties (2)

 

 

(0.76)

 

 

(0.60)

 

 

(0.69)

 

 

(0.95)

 

 

(0.75)

Production costs (3)

 

 

(0.07)

 

 

(0.06)

 

 

(0.10)

 

 

(0.11)

 

 

(0.09)

Netback

 

$

1.89

 

$

1.26

 

$

1.63

 

$

2.41

 

$

1.80

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales price (1)

 

$

2.58

 

$

1.14

 

$

1.59

 

$

2.16

 

$

1.88

Royalties (2)

 

 

(0.46)

 

 

(0.39)

 

 

(0.60)

 

 

(0.51)

 

 

(0.48)

Transportation

 

 

(0.11)

 

 

(0.07)

 

 

(0.07)

 

 

(0.11)

 

 

(0.09)

Production costs (3)

 

 

(1.56)

 

 

(2.13)

 

 

(2.49)

 

 

(3.06)

 

 

(2.19)

Netback

 

$

0.45

 

$

(1.45)

 

$

(1.57)

 

$

(1.52)

 

$

(0.88)

 

Notes:

(1)

Before the effects of commodity derivative instruments.

(2)

Includes production taxes.

(3)

Production costs are costs incurred to operate and maintain wells and related equipment and facilities, including operating costs of support equipment used in oil and gas activities and other costs of operating and maintaining those wells and related equipment and facilities. Examples of production costs include items such as field staff labour costs, costs of materials, supplies and fuel consumed and supplies utilized in operating the wells and related equipment (such as power (including gains and losses on electricity contracts), chemicals and lease rentals), repairs and maintenance costs, property taxes, insurance costs, costs of workovers, net processing and treating fees, overhead fees, taxes (other than income, capital, withholding or U.S. state production taxes) and other costs .

 

TAX HORIZON

 

The Corporation is subject to standard applicable corporate income taxes. Based on existing tax legislation, the Corporation’s available tax pools, expected capital expenditures and forecasted net income, the Corporation does not anticipate paying material cash taxes in either Canada or the United States until 2021.  These expectations may vary depending on numerous factors, including fluctuations in commodity prices, the Corporation's capital spending, changes in tax laws, and the nature and timing of the Corporation's acquisitions and divestments. As a result, the Corporation emphasizes that it is difficult to give guidance on future taxability as it operates within an industry that constantly changes. See " Risk Factors – Changes in laws or free trade agreements, including those affecting tax, royalties and other financial and trade matters, and interpretations of those laws and trade agreements, may adversely affect the Corporation and its securityholders ” .

 

For additional information, see Notes 2(i) and 12 to the Financial Statements and the information under the heading "Income Taxes" in the Corporation's MD&A, which can be found on its SEDAR profile at www.sedar.com  and on the Corporation's EDGAR profile at  www.sec.gov .

 

MARKETING ARRANGEMENTS AND FORWARD CONTRACTS

 

Crude Oil and NGLs

 

The Corporation's crude oil and NGLs production is marketed to a diverse portfolio of intermediaries and end users, generally on 30‑day continuously renewing contracts for crude oil in Canada,  negotiated contracts ranging from 30 days up to two years for crude oil in the U.S., and yearly contracts for NGLs in Canada, where terms fluctuate with the monthly spot markets. NGLs contracts in the U.S. are linked to processing arrangements  with pricing linked to the monthly spot markets. The Corporation received an average price (before transportation costs, royalties, and the effects of commodity derivative instruments) of $74.59/bbl for its crude oil and $28.31/bbl for its NGLs for the year ended December 31, 2018, compared to $58.69/bbl for its crude oil and $30.01/bbl for its NGLs for the year ended December 31, 2017.

18      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

 

In the United States, the Corporation transports its U.S. crude oil production to its buyers by pipeline and/or truck,  and may occasionally sell a portion to buyers who may utilize rail transportation (after title is transferred into the buyer’s name). In 2018, the Corporation received an average price differential for its U.S. Bakken crude oil of US$3.78/bbl below WTI, compared to an average of US$3.72/bbl below WTI in 2017. The Corporation has firm sales contracts in place for approximately   21,000 bbls/day, on average, during 2019 for its U.S. oil production, which includes an average of 16,000 bbls/day of physical sales with a fixed differential of US$3.00/bbl below WTI.  The Corporation also expects to transport a portion of its North Dakota crude oil production to the U.S. Gulf Coast, where it can further access export crude oil markets. The Corporation’s NGLs associated with its U.S. crude oil production volumes are marketed on its behalf by midstream companies in North Dakota and Montana.

 

In Canada, the Corporation typically transports its Canadian crude oil production to its buyers by pipeline and/or truck. The Corporation may occasionally sell a portion of its crude oil production to buyers who may use rail transportation (after title is transferred into the buyer’s name). The Corporation has firm transportation capacity for approximately 3,200 BOE/day of crude oil and natural gas liquids production in 2019, decreasing to approximately 1,400 BOE / day on average from 2020 to 2027.  Additionally, the Corporation has contracted firm NGLs fractionation agreements for 1,100 BOE/day through 2027.

 

Natural Gas

 

In marketing its natural gas production, the Corporation strives for a mix of contracts and customers. In 2018,  80% of the Corporation's natural gas production originated from its non-operated Marcellus interest in northeast Pennsylvania.   Pipeline egress out of the Marcellus region continued to come on-line during 2018. At times the Corporation curtailed natural gas production due to low regional spot pricing due to third party pipeline maintenance. See " Risk Factors – Lack of adequately developed infrastructure, and the impact of special interest groups on such development, may result in a decline in the Corporation's ability to market its oil and natural gas production ".  The Corporation delivered approximately 43% of its Marcellus production in 2018 onto the Transco Leidy Pipeline, with most of the remaining volumes delivered onto the Tennessee Gas Pipeline 300 Line in Pennsylvania. A portion was then transported to the Kentucky/Tennessee border. The Corporation has firm "must‑take" sales contracts for up to 65 MMcf/day of natural gas production in the Marcellus for terms of up to seven years with buyers who hold pipeline capacity on these and other pipelines in the region. The Corporation also has firm transportation agreements to transport gas within and out of the region for approximately 66 MMcf/day, with terms ending between 2020 and 2036. The Corporation holds firm transportation capacity for 30 MMcf/day for five years on the PennEast Pipeline project. The Federal Energy Regulatory Commission approved the project through the issuance of a certificate of public convenience and necessity in January 2018. The expected in-service date was revised due to state-level regulatory delays. Pending final state-level regulatory approvals and construction schedules, the in-service date is now expected to be in 2020.

 

The average price received by the Corporation (before transportation, royalties, and the effects of commodity derivative instruments) for its natural gas in 2018 was $3.42/Mcf compared to $3.21/Mcf for the year ended December 31, 2017. The Corporation received an average price differential for its U.S. Marcellus shale gas production of US$0.43/Mcf below NYMEX prices. Approximately 9% of the Corporation's natural gas production was associated natural gas production from its crude oil operations in North Dakota and Montana. The Corporation does not market these volumes directly, as they are marketed on Enerplus’ behalf by midstream companies.

 

In Canada, the Corporation sells its natural gas production at a mix of fixed and floating prices for a variety of terms ranging from spot sales to one year or longer. The Corporation's monthly sales portfolio reflected a mix of the daily and monthly market indices .   The Corporation sold the majority of its Canadian natural gas production under fixed AECO-NYMEX basis differential contracts, benefiting the Corporation’s Canadian natural gas differential, which averaged US$0.81/Mcf below NYMEX in 2018. Approximately 11% of the Corporation's total natural gas production originated in Canada in 2018 and received an average price  (before transportation, royalties, and the effects of commodity derivative instruments),  of $2.90/Mcf during the year. At December 31, 2018, the Corporation held firm service natural gas transportation contracts for its natural gas production in Canada for 2019 totalling 48.7 MMcf/day.

 

Future Commitments and Forward Contracts

 

The Corporation may use various types of derivative financial instruments and fixed price physical sales contracts to manage the risk related to fluctuating commodity prices. Absent such hedging activities, all of the crude oil and NGLs and the majority of natural gas production of the Corporation is sold into the open market at prevailing market prices, which exposes the Corporation to the risks associated with commodity price fluctuations and foreign exchange rates. See " Risk Factors ". Information regarding the Corporation's financial instruments is contained in Notes   14(b) and 14(c)(i) to the Financial Statements and under the heading " Results of Operations – Price Risk Management " in the Corporation's MD&A, each of which is available through the internet on the Corporation's website at  www.enerplus.com , on the Corporation's SEDAR profile at  www.sedar.com and on the Corporation's EDGAR profile at  www.sec.gov .

ENERPLUS 2018 ANNUAL INFORMATION FORM     19

 

 

Oil and Natural Gas Reserves 

 

SUMMARY OF RESERVES

 

All of the Corporation's reserves, including its U.S. reserves, have been evaluated in accordance with NI 51‑101. Independent reserves evaluations have been conducted on properties comprising approximately 95% of the net present value (discounted at 10%, before tax, using forecast prices and costs) of the Corporation's total proved plus probable reserves.

 

McDaniel, an independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties which comprise approximately 70% of the net present value (discounted at 10%, before tax, using forecast prices and costs) of the Corporation's proved plus probable reserves located in Canada and all of the Corporation's reserves associated with the Corporation's properties located in North Dakota,  Montana and Colorado.  McDaniel used the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2019 to prepare its report. The Corporation has evaluated the remaining 30% of the net present value of its Canadian properties using similar evaluation parameters, including the same forecast price and inflation rate assumptions utilized by McDaniel. McDaniel has reviewed the Corporation's internal evaluation of these properties.

 

NSAI, independent petroleum consultants based in Dallas, Texas, has evaluated all of the Corporation's reserves associated with the Corporation's properties in Pennsylvania. For consistency in the Corporation's reserves reporting, NSAI used the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2019 to prepare its report.

 

The Corporation used the average of the forecast exchange rates of GLJ, McDaniel and Sproule, set forth below, to convert U.S. dollar amounts in both the McDaniel and NSAI Reports to Canadian dollar amounts for presentation in this Annual Information Form.

 

The following sections and tables summarize, as at December 31, 2018, the Corporation's crude oil, NGLs and natural gas reserves and the estimated net present values of future net revenues associated with such reserves, together with certain information, estimates and assumptions associated with such reserves estimates. The data contained in the tables is a summary of the evaluations and, as a result, the tables may contain slightly different numbers than the evaluations themselves due to rounding. Additionally, the columns and rows in the tables may not add due to rounding. For information relating to the changes in the volumes of the Corporation's reserves from December 31, 2017 to December 31, 2018, see "–  Reconciliation of Reserves " below.

 

All estimates of future net revenues are stated prior to provision for interest and general and administrative expenses and after deduction of royalties and estimated future capital expenditures, and are presented both before and after deducting income taxes. For additional information, see " Business of the Corporation – Tax Horizon ", " Industry Conditions " and " Risk Factors " in this Annual Information Form.

 

With respect to pricing information in the following reserves information, the wellhead oil prices were adjusted for quality and transportation based on historical actual prices. The natural gas prices were adjusted, where necessary, based on historical pricing based on heating values and transportation. The NGLs prices were adjusted to reflect historical average prices received.

 

It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained, and variances could be material. The reserves estimates of the Corporation's crude oil, NGLs and natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in " Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information " in conjunction with the following tables and notes.

 

20      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

The following tables set forth the estimated gross and net reserves volumes and net present value of future net revenue attributable to the Corporation's reserves at December 31, 2018, using forecast price and cost cases.

 

Summary of Oil and Gas Reserves (Forecast Prices and Costs) 

 

As of December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OIL AND NATURAL GAS RESERVES

 

 

Light &

 

 

 

 

 

 

 

 

 

Natural Gas

 

Conventional

 

 

 

 

 

 

 

 

RESERVES

 

Medium Oil

 

Heavy Oil

 

Tight Oil

 

Liquids

 

Natural Gas

 

Shale Gas

 

Total

CATEGORY

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(MMcf)

 

(MMcf)

 

(MMcf)

 

(MMcf)

 

(MBOE)

 

(MBOE)

Proved Developed Producing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

9,062

 

7,514

 

17,969

 

15,506

 

 -

 

 -

 

1,178

 

1,066

 

28,707

 

29,245

 

1,059

 

1,006

 

33,170

 

29,127

United States

 

 -

 

 -

 

 -

 

 -

 

58,284

 

46,815

 

7,265

 

5,808

 

 -

 

 -

 

590,831

 

474,628

 

164,020

 

131,729

Total

 

9,062

 

7,514

 

17,969

 

15,506

 

58,284

 

46,815

 

8,443

 

6,875

 

28,707

 

29,245

 

591,890

 

475,633

 

197,191

 

160,856

Proved Developed Non-Producing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

15

 

14

 

135

 

124

 

 -

 

 -

 

91

 

65

 

2,213

 

2,081

 

 -

 

 -

 

609

 

550

United States

 

 -

 

 -

 

 -

 

 -

 

921

 

751

 

47

 

38

 

 -

 

 -

 

3,748

 

3,039

 

1,593

 

1,295

Total

 

15

 

14

 

135

 

124

 

921

 

751

 

138

 

103

 

2,213

 

2,081

 

3,748

 

3,039

 

2,202

 

1,845

Proved Undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

560

 

489

 

3,077

 

2,560

 

 -

 

 -

 

 1

 

 1

 

88

 

73

 

 -

 

 -

 

3,653

 

3,062

United States

 

 -

 

 -

 

 -

 

 -

 

47,325

 

37,881

 

5,201

 

4,165

 

 -

 

 -

 

253,426

 

200,992

 

94,763

 

75,544

Total

 

560

 

489

 

3,077

 

2,560

 

47,325

 

37,881

 

5,202

 

4,166

 

88

 

73

 

253,426

 

200,992

 

98,416

 

78,606

Total Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

9,637

 

8,017

 

21,181

 

18,189

 

 -

 

 -

 

1,270

 

1,132

 

31,007

 

31,399

 

1,059

 

1,006

 

37,432

 

32,740

United States

 

 -

 

 -

 

 -

 

 -

 

106,530

 

85,447

 

12,513

 

10,011

 

 -

 

 -

 

848,004

 

678,658

 

260,376

 

208,567

Total

 

9,637

 

8,017

 

21,181

 

18,189

 

106,530

 

85,447

 

13,783

 

11,143

 

31,007

 

31,399

 

849,063

 

679,664

 

297,809

 

241,307

Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

3,024

 

2,387

 

7,215

 

5,985

 

 -

 

 -

 

452

 

409

 

10,129

 

10,168

 

215

 

204

 

12,414

 

10,510

United States

 

 -

 

 -

 

 -

 

 -

 

60,631

 

48,509

 

6,825

 

5,456

 

 -

 

 -

 

300,234

 

238,310

 

117,495

 

93,684

Total

 

3,024

 

2,387

 

7,215

 

5,985

 

60,631

 

48,509

 

7,277

 

5,865

 

10,129

 

10,168

 

300,449

 

238,514

 

129,909

 

104,194

Total Proved Plus Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

12,660

 

10,404

 

28,395

 

24,174

 

 -

 

 -

 

1,723

 

1,541

 

41,137

 

41,567

 

1,274

 

1,210

 

49,847

 

43,249

United States

 

 -

 

 -

 

 -

 

 -

 

167,160

 

133,956

 

19,338

 

15,467

 

 -

 

 -

 

1,148,238

 

916,968

 

377,871

 

302,251

Total

 

12,660

 

10,404

 

28,395

 

24,174

 

167,160

 

133,956

 

21,060

 

17,008

 

41,137

 

41,567

 

1,149,511

 

918,178

 

427,718

 

345,501

 

 

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     21

 

 

Summary of Net Present Value of Future Net Revenue 

Attributable to Oil and Gas Reserves (Forecast Prices and Costs)

 

As of December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/Year)

 

 

 

 

 

Before Deducting Income Taxes

 

After Deducting Income Taxes (1)

 

Unit

RESERVES CATEGORY

    

0%

    

5%

    

10%

    

15%

    

20%

    

0%

    

5%

    

10%

    

15%

    

20%

    

Value (2)

 

 

(in $ millions)

 

$/BOE

Proved Developed Producing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

907

 

665

 

522

 

429

 

365

 

907

 

665

 

522

 

429

 

365

 

 

$17.90

United States

 

3,600

 

2,592

 

2,046

 

1,711

 

1,484

 

3,101

 

2,301

 

1,855

 

1,575

 

1,383

 

 

$15.53

Total

 

4,507

 

3,257

 

2,568

 

2,140

 

1,849

 

4,008

 

2,966

 

2,376

 

2,005

 

1,748

 

 

$15.96

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Developed Non‑Producing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

(12)

 

(11)

 

(10)

 

(10)

 

(9)

 

(12)

 

(11)

 

(10)

 

(10)

 

(9)

 

 

($18.93)

United States

 

29

 

23

 

19

 

16

 

13

 

22

 

17

 

14

 

12

 

10

 

 

$14.47

Total

 

17

 

12

 

 8

 

 6

 

 4

 

10

 

 6

 

 4

 

 2

 

 1

 

 

$4.51

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

92

 

63

 

43

 

30

 

20

 

70

 

55

 

40

 

29

 

20

 

 

$14.18

United States

 

1,623

 

995

 

652

 

437

 

291

 

1,179

 

717

 

460

 

298

 

187

 

 

$8.63

Total

 

1,714

 

1,057

 

695

 

467

 

311

 

1,249

 

772

 

500

 

326

 

207

 

 

$8.84

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

987

 

716

 

555

 

449

 

377

 

965

 

708

 

551

 

448

 

376

 

 

$16.94

United States

 

5,251

 

3,610

 

2,717

 

2,163

 

1,788

 

4,301

 

3,035

 

2,329

 

1,885

 

1,581

 

 

$13.03

Total

 

6,238

 

4,326

 

3,271

 

2,613

 

2,165

 

5,266

 

3,743

 

2,880

 

2,333

 

1,956

 

 

$13.56

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

437

 

253

 

166

 

119

 

90

 

319

 

195

 

136

 

102

 

80

 

 

$15.82

United States

 

3,438

 

1,827

 

1,145

 

792

 

582

 

2,519

 

1,338

 

835

 

576

 

423

 

 

$12.22

Total

 

3,875

 

2,080

 

1,311

 

911

 

672

 

2,838

 

1,533

 

971

 

678

 

503

 

 

$12.58

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Proved Plus Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

1,423

 

969

 

721

 

568

 

467

 

1,284

 

903

 

687

 

550

 

456

 

 

$16.67

United States

 

8,690

 

5,436

 

3,861

 

2,955

 

2,370

 

6,820

 

4,373

 

3,165

 

2,462

 

2,004

 

 

$12.78

Total

 

10,113

 

6,405

 

4,582

 

3,523

 

2,837

 

8,105

 

5,277

 

3,851

 

3,011

 

2,460

 

 

$13.26

 

Notes:

(1)  Income tax calculations are based on the forecast cash flows of reserves volumes only, taking into consideration the forecast capital required to develop the reserves, and having regard for remaining corporate tax pools at the effective date, applicable deductions and appropriate federal, provincial and state tax rates.

(2)    Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year, and net reserves. The unit values are based on net reserves volumes.

 

22      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

FORECAST PRICES AND COSTS

 

The forecast price and cost case assumes no legislative or regulatory amendments, and includes the effects of inflation. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2019   (utilized by McDaniel, NSAI and by the Corporation in its internal evaluations for consistency in the Corporation's reserves reporting), and the following inflation and exchange rate assumptions:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NATURAL GAS LIQUIDS

 

 

 

 

 

 

CRUDE OIL

 

NATURAL GAS

 

Edmonton Par Price

 

 

 

 

 

    

 

    

 

    

 

    

 

    

 

    

 

    

 

    

 

    

Condensate

    

 

    

 

 

 

 

 

 

 

 

 

Sask

 

Alberta

 

U.S. Henry

 

 

 

 

 

&

 

 

 

 

 

 

 

 

Edmonton

 

Alberta

 

Cromer

 

AECO

 

Hub

 

 

 

 

 

Natural

 

Inflation

 

Exchange

Year

 

WTI (1)

 

Light (2)

 

Heavy (3)

 

Medium (4)

 

Spot Prices

 

Gas Price

 

Propane

 

Butanes

 

Gasolines

 

Rate

 

Rate

 

 

($US/bbl)

 

($Cdn/bbl)

 

($Cdn/bbl)

 

($Cdn/bbl)

 

($Cdn/MMbtu)

 

($US/MMbtu)

 

($Cdn/bbl)

 

($Cdn/bbl)

 

($Cdn/bbl)

 

(%/year)

 

($US/$Cdn)

2019

 

58.58

 

67.30

 

43.92

 

63.99

 

1.88

 

3.00

 

26.13

 

27.32

 

70.10

 

 -

 

0.757

2020

 

64.60

 

75.84

 

52.76

 

71.38

 

2.31

 

3.13

 

31.27

 

41.10

 

79.21

 

2.0

 

0.782

2021

 

68.20

 

80.17

 

59.10

 

75.14

 

2.74

 

3.33

 

34.58

 

49.28

 

83.33

 

2.0

 

0.797

2022

 

71.00

 

83.22

 

61.60

 

78.06

 

3.05

 

3.51

 

37.25

 

55.65

 

86.20

 

2.0

 

0.803

2023

 

72.81

 

85.34

 

63.39

 

80.06

 

3.21

 

3.62

 

38.73

 

57.92

 

88.16

 

2.0

 

0.807

2024

 

74.59

 

87.33

 

65.14

 

81.96

 

3.31

 

3.70

 

39.75

 

59.27

 

90.20

 

2.0

 

0.808

2025

 

76.42

 

89.50

 

66.99

 

84.02

 

3.39

 

3.77

 

40.76

 

60.77

 

92.43

 

2.0

 

0.808

2026

 

78.40

 

91.89

 

69.06

 

86.29

 

3.46

 

3.85

 

41.93

 

62.37

 

94.87

 

2.0

 

0.808

2027

 

79.98

 

93.76

 

70.60

 

88.08

 

3.54

 

3.92

 

42.84

 

63.65

 

96.80

 

2.0

 

0.808

2028

 

81.59

 

95.68

 

72.17

 

89.90

 

3.62

 

4.01

 

43.80

 

64.97

 

98.79

 

2.0

 

0.808

2029

 

83.22

 

97.60

 

73.62

 

91.69

 

3.69

 

4.09

 

44.68

 

66.27

 

100.76

 

2.0

 

0.808

2030

 

84.89

 

99.55

 

75.09

 

93.53

 

3.77

 

4.17

 

45.57

 

67.60

 

102.78

 

2.0

 

0.808

2031

 

86.58

 

101.54

 

76.59

 

95.40

 

3.84

 

4.25

 

46.48

 

68.95

 

104.83

 

2.0

 

0.808

2032

 

88.31

 

103.57

 

78.12

 

97.31

 

3.92

 

4.34

 

47.41

 

70.33

 

106.93

 

2.0

 

0.808

2033

 

90.08

 

105.64

 

79.68

 

99.25

 

4.00

 

4.42

 

48.36

 

71.74

 

109.07

 

2.0

 

0.808

Thereafter

 

(5)

 

(5)

 

(5)

 

(5)

 

(5)

 

(5)

 

(5)

 

(5)

 

(5)

 

(5)

 

0.808

 

Notes:   

(1) West Texas Intermediate at Cushing Oklahoma 40 o API/0.5% sulphur

(2)   Edmonton Light Sweet 40 o API/0.3% sulphur

(3)   Heavy Crude Oil 12 o API at Hardisty, Alberta (after deducting blending costs to reach pipeline quality)

(4)   Midale Cromer Crude Oil 29 o API/2.0% sulphur

(5)   Escalation is approximately 2% per year thereafter

 

In 2018, the Corporation received a weighted average price (before transportation costs, royalties, and the effects of commodity derivative instruments) of $74.59/bbl for crude oil, $28.31/bbl for natural gas liquids and $3.42/Mcf for natural gas.    

 

UNDISCOUNTED FUTURE NET REVENUE BY RESERVES CATEGORY  

 

The undiscounted total future net revenue by reserves category as of December 31, 2018, using forecast prices and costs, is set forth below (columns or rows may not add due to rounding):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

    

 

    

 

    

 

    

 

    

Future Net

    

 

    

Future Net

 

 

 

 

 

 

 

 

 

 

Abandonment

 

Revenue

 

 

 

Revenue

 

 

 

 

 

 

 

 

 

 

and

 

Before

 

 

 

After

 

 

 

 

 

 

Operating

 

Development

 

Reclamation

 

Income

 

Income

 

Income

RESERVES CATEGORY

 

Revenue

 

Royalties (1)

 

Costs

 

Costs

 

Costs

 

Taxes

 

Taxes

 

Taxes (2)

 

 

(in $ millions)

Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

2,389

 

365

 

878

 

120

 

40

 

987

 

21

 

965

United States

 

12,583

 

3,255

 

2,634

 

1,228

 

215

 

5,251

 

950

 

4,301

Total

 

14,973

 

3,619

 

3,512

 

1,348

 

255

 

6,238

 

972

 

5,266

Proved Plus Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

3,322

 

531

 

1,188

 

135

 

44

 

1,423

 

139

 

1,284

United States

 

20,114

 

5,263

 

4,001

 

1,887

 

274

 

8,690

 

1,869

 

6,820

Total

 

23,436

 

5,794

 

5,190

 

2,022

 

318

 

10,113

 

2,008

 

8,105

 

Notes:

(1) Royalties include any net profits interests paid, as well as the Saskatchewan Corporation Capital Tax Surcharge.

(2) Income tax calculations are based on the forecast cash flows of reserves volumes only, taking into consideration the forecast capital required to develop the reserves, and having regard for remaining corporate tax pools at the effective date, applicable deductions   and appropriate federal, provincial and state tax rates .

ENERPLUS 2018 ANNUAL INFORMATION FORM     23

 

 

 

 

 

NET PRESENT VALUE OF FUTURE NET REVENUE BY RESERVES CATEGORY AND PRODUCT TYPE

 

The net present value of future net revenue before income taxes by reserves category and product type as of December 31, 2018, using forecast prices and costs and discounted at 10% per year, is set forth below:

 

 

 

 

 

 

 

 

 

 

 

 

Future Net

 

 

 

 

 

 

Revenue

 

 

 

 

 

 

Before Income

 

 

 

 

 

 

Taxes

 

 

RESERVES CATEGORY

   

PRODUCT TYPE

   

(Discounted at 10%)

   

Unit Value (1)

 

 

 

 

(in $ millions)

 

($/bbl; $/Mcf)

Canada

 

 

 

 

 

 

Proved Reserves

 

Light and Medium Oil (including solution gas and by-products) (2)

 

184,404

 

23.08

 

 

Heavy Oil (including solution gas and by-products) (2)

 

335,429

 

18.44

 

 

Tight Oil (2)

 

n/a

 

n/a

 

 

Conventional Natural Gas (including by-products) (3)

 

31,881

 

1.20

 

 

Shale Gas (3)

 

2,797

 

2.78

 

 

Total

 

554,511

 

 

Proved Plus Probable Reserves

 

Light and Medium Oil (including solution gas and by-products) (2)

 

242,656

 

23.40

 

 

Heavy Oil (including solution gas and by-products) (2)

 

434,184

 

17.96

 

 

Tight Oil (2)

 

n/a

 

n/a

 

 

Conventional Natural Gas (including by-products) (3)

 

40,697

 

1.15

 

 

Shale Gas (3)

 

3,268

 

2.70

 

 

Total

 

720,805

 

 

United States

 

 

 

 

 

 

Proved Reserves

 

Light and Medium Oil (including solution gas and by-products) (2)

 

n/a

 

n/a

 

 

Heavy Oil (including solution gas and by-products) (2)

 

n/a

 

n/a

 

 

Tight Oil (2)

 

2,013,667

 

23.57

 

 

Conventional Natural Gas (including by-products) (3)

 

n/a

 

n/a

 

 

Shale Gas (4)

 

702,959

 

1.15

 

 

Total

 

2,716,626

 

 

Proved Plus Probable Reserves

 

Light and Medium Oil (including solution gas and by-products) (2)

 

n/a

 

n/a

 

 

Heavy Oil (including solution gas and by-products) (2)

 

n/a

 

n/a

 

 

Tight Oil (2)

 

3,011,904

 

22.48

 

 

Conventional Natural Gas (including by-products) (3)

 

n/a

 

n/a

 

 

Shale Gas (4)

 

849,393

 

1.03

 

 

Total

 

3,861,298

 

 

Total

 

 

 

 

 

 

Proved Reserves

 

Light and Medium Oil (including solution gas and by-products) (2)

 

184,404

 

 

 

 

Heavy Oil (including solution gas and by-products) (2)

 

335,429

 

 

 

 

Tight Oil (2)

 

2,013,667

 

 

 

 

Conventional Natural Gas (including by-products) (3)

 

31,881

 

 

 

 

Shale Gas (3)(4)

 

705,756

 

 

 

 

Total

 

3,271,137

 

 

Proved Plus Probable Reserves

 

Light and Medium Oil (including solution gas and by-products) (2)

 

242,656

 

 

 

 

Heavy Oil (including solution gas and by-products) (2)

 

434,184

 

 

 

 

Tight Oil (2)

 

3,011,904

 

 

 

 

Conventional Natural Gas (including by-products) (3)

 

40,697

 

 

 

 

Shale Gas (3)(4)

 

852,661

 

 

 

 

Total

 

4,582,103

 

 

 

Notes:

(1)

Unit values are calculated using the 10% discounted rate divided by the major product type net reserves for each group.

(2)

Including net present value of solution gas and other by-products.

(3)

Including net present value of by-products, but excluding solution gas and by-products from oil wells .

(4)

No by-product oil or NGLs are associated with U.S. shale gas .  

 

 

24      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

ESTIMATED PRODUCTION FOR GROSS RESERVES ESTIMATES

 

The volume of total production for the Corporation estimated for 2019 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual 2019 production (including from the Fort Berthold and Marcellus properties in the separate tables below) may vary from the estimates provided by McDaniel and NSAI as the Corporation's actual development programs, timing and priorities may differ from the forecast of development by McDaniel and NSAI. Columns may not add due to rounding.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Proved Reserves

 

 

Canada

 

United States

 

 

Estimated 2019

 

Estimated 2019

 

Estimated 2019

 

Estimated 2019

 

 

Aggregate

 

Average Daily

 

Aggregate

 

Average Daily

Product Type

 

Production

 

Production

 

Production

 

Production

Crude Oil

    

 

    

 

    

 

    

 

    

 

    

 

    

 

    

 

Light and Medium Crude Oil

 

1,476

 

Mbbls

 

4,044

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Heavy Oil

 

1,873

 

Mbbls

 

5,132

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Tight Oil

 

-

 

Mbbls

 

-

 

bbls/day

 

15,670

 

Mbbls

 

42,933

 

bbls/day

Total Crude Oil

 

3,349

 

Mbbls

 

9,176

 

bbls/day

 

15,670

 

Mbbls

 

42,933

 

bbls/day

Natural Gas Liquids

 

225

 

Mbbls

 

618

 

bbls/day

 

1,719

 

Mbbls

 

4,708

 

bbls/day

Total Liquids

 

3,575

 

Mbbls

 

9,793

 

bbls/day

 

17,389

 

Mbbls

 

47,641

 

bbls/day

Conventional Natural Gas

 

6,993

 

MMcf

 

19,159

 

Mcf/day

 

-

 

MMcf

 

-

 

Mcf/day

Shale Gas

 

119

 

MMcf

 

325

 

Mcf/day

 

80,217

 

MMcf

 

219,773

 

Mcf/day

Total

 

4,760

 

MBOE

 

13,041

 

BOE/day

 

30,758

 

MBOE

 

84,270

 

BOE/day

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Probable Reserves

 

 

Canada

 

United States

 

 

Estimated 2019

 

Estimated 2019

 

Estimated 2019

 

Estimated 2019

 

 

Aggregate

 

Average Daily

 

Aggregate

 

Average Daily

Product Type

 

Production

 

Production

 

Production

 

Production

Crude Oil

  

 

    

 

    

             

    

 

    

 

    

 

    

              

    

 

Light and Medium Crude Oil

 

92

 

Mbbls

 

251

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Heavy Oil

 

59

 

Mbbls

 

162

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Tight Oil

 

-

 

Mbbls

 

-

 

bbls/day

 

1,081

 

Mbbls

 

2,961

 

bbls/day

Total Crude Oil

 

151

 

Mbbls

 

413

 

bbls/day

 

1,081

 

Mbbls

 

2,961

 

bbls/day

Natural Gas Liquids

 

20

 

Mbbls

 

55

 

bbls/day

 

111

 

Mbbls

 

304

 

bbls/day

Total Liquids

 

171

 

Mbbls

 

468

 

bbls/day

 

1,192

 

Mbbls

 

3,265

 

bbls/day

Conventional Natural Gas

 

517

 

MMcf

 

1,417

 

Mcf/day

 

-

 

MMcf

 

-

 

Mcf/day

Shale Gas

 

 2

 

MMcf

 

 5

 

Mcf/day

 

5,963

 

MMcf

 

16,338

 

Mcf/day

Total

 

257

 

MBOE

 

705

 

BOE/day

 

2,186

 

MBOE

 

5,988

 

BOE/day

 

The tables below set forth McDaniel's and NSAI’s estimated 2019 production for the Corporation's Fort Berthold property located in North Dakota, United States, and the Marcellus property, located in Pennsylvania, United States, respectively, as each field is estimated to account for more than 20% of the above estimate of the Corporation's 2019 production.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Proved Reserves

 

 

Fort Berthold

 

Marcellus

 

 

Estimated 2019

 

Estimated 2019

 

Estimated 2019

 

Estimated 2019

 

 

Aggregate

 

Average Daily

 

Aggregate

 

Average Daily

Product Type

 

Production

 

Production

 

Production

 

Production

Crude Oil

 

 

    

 

    

 

    

 

    

 

    

 

    

 

    

 

Light and Medium Crude Oil

 

-

 

Mbbls

 

-

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Heavy Oil

 

-

 

Mbbls

 

-

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Tight Oil

 

14,632

 

Mbbls

 

40,087

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Total Crude Oil

 

14,632

 

Mbbls

 

40,087

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Natural Gas Liquids

 

1,698

 

Mbbls

 

4,651

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Total Liquids

 

16,329

 

Mbbls

 

44,738

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Conventional Natural Gas

 

-

 

MMcf

 

-

 

Mcf/day

 

-

 

MMcf

 

-

 

Mcf/day

Shale Gas

 

8,488

 

MMcf

 

23,254

 

Mcf/day

 

69,816

 

MMcf

 

191,276

 

Mcf/day

Total

 

17,744

 

MBOE

 

48,614

 

BOE/day

 

11,636

 

MBOE

 

31,879

 

BOE/day

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     25

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Probable Reserves

 

 

Fort Berthold

    

Marcellus

 

 

Estimated 2019

 

Estimated 2019

 

Estimated 2019

 

Estimated 2019

 

 

Aggregate

 

Average Daily

 

Aggregate

 

Average Daily

Product Type

 

Production

 

Production

 

Production

 

Production

Crude Oil

    

 

    

 

    

             

    

 

    

 

    

 

    

              

    

 

Light and Medium Crude Oil

 

-

 

Mbbls

 

-

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Heavy Oil

 

-

 

Mbbls

 

-

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Tight Oil

 

793

 

Mbbls

 

2,174

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Total Crude Oil

 

793

 

Mbbls

 

2,174

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Natural Gas Liquids

 

84

 

Mbbls

 

230

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Total Liquids

 

877

 

Mbbls

 

2,404

 

bbls/day

 

-

 

Mbbls

 

-

 

bbls/day

Conventional Natural Gas

 

-

 

MMcf

 

-

 

Mcf/day

 

-

 

MMcf

 

-

 

Mcf/day

Shale Gas

 

420

 

MMcf

 

1,149

 

Mcf/day

 

5,442

 

MMcf

 

14,910

 

Mcf/day

Total

 

947

 

MBOE

 

2,595

 

BOE/day

 

907

 

MBOE

 

2,485

 

BOE/day

 

 

 

FUTURE DEVELOPMENT COSTS  

 

The amount of development costs deducted in the estimation of net present value of future net revenue is set forth below. The Corporation intends to fund its development activities through cash,  internally generated cash flow and/or debt.  The Corporation does not anticipate that the cost of obtaining the funds required for these development activities will have a material effect on the Corporation's disclosed oil and gas reserves or future net revenue attributable to those reserves. For additional information, see " Business of the Corporation – Capital Expenditures and Costs Incurred ".

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CANADA

 

UNITED STATES

 

 

 

 

 

 

Proved Plus

 

 

 

 

 

Proved Plus

 

 

Proved Reserves

 

Probable Reserves

 

Proved Reserves

 

Probable Reserves

 

 

 

 

Discounted

 

 

 

Discounted

 

 

 

Discounted

 

 

 

Discounted

Year

    

Undiscounted

    

at 10%/year

    

Undiscounted

    

at 10%/year

    

Undiscounted

    

at 10%/year

    

Undiscounted

    

at 10%/year

 

 

(in $ millions)

 

2019

 

43

 

41

 

43

 

41

 

613

 

591

 

671

 

647

2020

 

37

 

32

 

37

 

32

 

490

 

424

 

506

 

437

2021

 

11

 

 9

 

19

 

15

 

95

 

76

 

505

 

397

2022

 

10

 

 7

 

17

 

12

 

24

 

18

 

146

 

107

2023

 

 8

 

 5

 

 7

 

 5

 

 5

 

 3

 

58

 

38

2024

 

 6

 

 4

 

 6

 

 4

 

 -

 

 -

 

 1

 

 1

Remainder

 

 5

 

 3

 

 6

 

 3

 

-

 

 -

 

 -

 

 -

Total

 

120

 

101

 

135

 

112

 

1,228

 

1,112

 

1,887

 

1,627

 

 

 

RECONCILIATION OF RESERVES

 

Overview

 

The Corporation's total gross proved plus probable reserves at December 31, 2018 were 427.7 MMBOE, an increase of approximately 8% from year‑end 2017. The Corporation's gross proved plus probable crude oil and NGLs reserves were 229.3 MMBOE and represented approximately 54% of total proved plus probable gross reserves, up 8% from year‑end 2017. The Corporation replaced approximately 194% of its 2018 gross production through its exploration and development program, adding approximately 65.7 MMBOE of proved plus probable reserves, including revisions and economic factors. Approximately 54% of the additions, including revisions and economic factors, were crude oil and NGLs, representing the replacement of 198% of the Corporation's 2018 crude oil and NGLs production. Of the Corporation’s approximately 65.7 MMBOE of proved plus probable additions, including revisions and economic factors, 35.1 MMBOE is attributed to the Fort Berthold property and 31.2 MMBOE (187.4 Bcf) to the Marcellus shale gas property.

 

The Corporation sold 1.9 MMBOE of proved plus probable reserves in 2018, the majority of which were associated with Canadian properties. Total proved plus probable conventional natural gas reserves decreased by approximately 47% from year‑end 2017 as a result of these divestments and the truncation of reserves volumes in the Tommy Lakes asset in 2020.

26      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

The following tables reconcile the Corporation's gross crude oil and natural gas reserves from December 31, 2017 to December 31, 2018, by country and in total, using forecast prices and costs. Certain columns may not add due to rounding.

 

CANADIAN OIL AND GAS RESERVES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Light & Medium Oil

 

Heavy Oil

 

Tight Oil

 

Natural Gas Liquids

 

 

 

 

 

 

 

Proved

 

 

 

 

 

Proved

 

 

 

 

 

Proved

 

 

 

 

 

Proved

CANADA

 

 

 

 

 

Plus

 

 

 

 

 

Plus

 

 

 

 

 

Plus

 

 

 

 

 

Plus

Factors

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

December 31, 2017

 

8,890

 

2,719

 

11,609

 

22,552

 

7,635

 

30,187

 

 -

 

 -

 

 -

 

1,935

 

831

 

2,767

Acquisitions

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

Dispositions

 

(2)

 

(1)

 

(3)

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

(70)

 

(35)

 

(105)

Discoveries

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

Extensions and Improved Recovery

 

1,501

 

1,150

 

2,651

 

500

 

1,023

 

1,522

 

 -

 

 -

 

 -

 

42

 

20

 

61

Economic Factors

 

64

 

(109)

 

(45)

 

127

 

25

 

152

 

 -

 

 -

 

 -

 

(82)

 

(87)

 

(169)

Technical Revisions

 

1,007

 

(735)

 

272

 

(437)

 

(1,468)

 

(1,906)

 

 -

 

 -

 

 -

 

(231)

 

(277)

 

(508)

Production

 

(1,823)

 

 -

 

(1,823)

 

(1,560)

 

 -

 

(1,560)

 

 -

 

 -

 

 -

 

(324)

 

 -

 

(324)

December 31, 2018

 

9,637

 

3,024

 

12,660

 

21,181

 

7,215

 

28,395

 

 -

 

 -

 

 -

 

1,270

 

452

 

1,723

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional Natural Gas

 

Shale Gas

 

Total

 

 

 

 

 

 

 

Proved

 

 

 

 

 

Proved

 

 

 

 

 

Proved

CANADA

 

 

 

 

 

Plus

 

 

 

 

 

Plus

 

 

 

 

 

Plus

Factors

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MBOE)

    

(MBOE)

    

(MBOE)

December 31, 2017

 

55,992

 

21,289

 

77,281

 

1,367

 

349

 

1,715

 

42,937

 

14,792

 

57,729

Acquisitions

 

 -

 

 -

 

 -

 

-

 

-

 

-

 

 -

 

 -

 

 -

Dispositions

 

(6,447)

 

(2,293)

 

(8,741)

 

 -

 

 -

 

 -

 

(1,147)

 

(418)

 

(1,565)

Discoveries

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

Extensions and Improved Recovery

 

976

 

395

 

1,372

 

-

 

-

 

-

 

2,205

 

2,258

 

4,463

Economic Factors

 

(1,597)

 

(1,523)

 

(3,120)

 

(9)

 

 1

 

(8)

 

(159)

 

(425)

 

(584)

Technical Revisions

 

(8,602)

 

(7,739)

 

(16,341)

 

(176)

 

(135)

 

(311)

 

(1,124)

 

(3,793)

 

(4,917)

Production

 

(9,314)

 

-

 

(9,314)

 

(123)

 

-

 

(123)

 

(5,280)

 

-

 

(5,280)

December 31, 2018

 

31,007

 

10,129

 

41,137

 

1,059

 

215

 

1,274

 

37,432

 

12,414

 

49,847

 

UNITED STATES OIL AND GAS RESERVES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Light & Medium Oil

 

Heavy Oil

 

Tight Oil

 

Natural Gas Liquids

 

 

  

 

  

 

  

Proved

  

 

  

 

  

Proved

  

 

  

 

  

Proved

  

 

  

 

  

Proved

UNITED STATES

 

 

 

 

 

Plus

 

 

 

 

 

Plus

 

 

 

 

 

Plus

 

 

 

 

 

Plus

Factors

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

    

(Mbbls)

December 31, 2017

 

-

 

-

 

-

 

-

 

-

 

-

 

91,101

 

58,125

 

149,227

 

11,065

 

6,921

 

17,985

Acquisitions

 

-

 

-

 

-

 

-

 

-

 

-

 

175

 

39

 

214

 

23

 

 5

 

28

Dispositions

 

-

 

-

 

-

 

-

 

-

 

-

 

(239)

 

(65)

 

(305)

 

(25)

 

(7)

 

(32)

Discoveries

 

-

 

-

 

-

 

-

 

-

 

-

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

Extensions and Improved Recovery

 

-

 

-

 

-

 

-

 

-

 

-

 

21,485

 

13,675

 

35,160

 

2,251

 

1,377

 

3,628

Economic Factors

 

-

 

-

 

-

 

-

 

-

 

-

 

(84)

 

(71)

 

(155)

 

(17)

 

(8)

 

(26)

Technical Revisions

 

-

 

-

 

-

 

-

 

-

 

-

 

7,236

 

(11,073)

 

(3,836)

 

463

 

(1,462)

 

(999)

Production

 

-

 

-

 

-

 

-

 

-

 

-

 

(13,144)

 

 -

 

(13,144)

 

(1,246)

 

 -

 

(1,246)

December 31, 2018

 

-

 

-

 

-

 

-

 

-

 

-

 

106,530

 

60,631

 

167,160

 

12,513

 

6,825

 

19,338

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional Natural Gas

 

Shale Gas

 

Total

 

 

  

 

  

 

  

Proved

  

 

  

 

  

Proved

  

 

  

 

  

Proved

UNITED STATES

 

 

 

 

 

Plus

 

 

 

 

 

Plus

 

 

 

 

 

Plus

Factors

 

Proved

Probable

Probable

 

Proved

Probable

Probable

 

Proved

Probable

Probable

 

     

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MBOE)

    

(MBOE)

    

(MBOE)

December 31, 2017

 

 -

 

 -

 

 -

 

801,651

 

233,393

 

1,035,045

 

235,775

 

103,945

 

339,719

Acquisitions

 

 -

 

 -

 

 -

 

114

 

26

 

139

 

217

 

48

 

265

Dispositions

 

 -

 

 -

 

 -

 

(126)

 

(37)

 

(162)

 

(286)

 

(78)

 

(364)

Discoveries

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

Extensions and Improved Recovery

 

 -

 

 -

 

 -

 

77,554

 

70,598

 

148,152

 

36,661

 

26,819

 

63,480

Economic Factors

 

 -

 

 -

 

 -

 

(1,232)

 

548

 

(683)

 

(306)

 

12

 

(294)

Technical Revisions

 

 -

 

 -

 

 -

 

54,734

 

(4,295)

 

50,440

 

16,821

 

(13,251)

 

3,571

Production

 

 -

 

 -

 

 -

 

(84,691)

 

 -

 

(84,691)

 

(28,506)

 

 -

 

(28,506)

December 31, 2018

 

 -

 

 -

 

 -

 

848,004

 

300,234

 

1,148,238

 

260,376

 

117,495

 

377,871

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     27

 

 

TOTAL OIL AND GAS RESERVES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Light & Medium Oil

 

Heavy Oil

 

Tight Oil

 

Natural Gas Liquids

 

  

 

  

 

  

Proved

  

 

  

 

  

Proved

  

 

  

 

  

Proved

  

 

  

 

  

Proved

TOTAL

 

 

 

 

 

Plus

 

 

 

 

 

Plus

 

 

 

 

 

Plus

 

 

 

 

 

Plus

Factors

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

Proved

 

Probable

 

Probable

 

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

December 31, 2017

 

8,890

 

2,719

 

11,609

 

22,552

 

7,635

 

30,187

 

91,101

 

58,125

 

149,227

 

13,000

 

7,752

 

20,752

Acquisitions

 

 -

 

 -

 

 -

 

-

 

-

 

-

 

175

 

39

 

214

 

23

 

 5

 

28

Dispositions

 

(2)

 

(1)

 

(3)

 

 -

 

 -

 

 -

 

(239)

 

(65)

 

(305)

 

(96)

 

(42)

 

(137)

Discoveries

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

Extensions and Improved Recovery

 

1,501

 

1,150

 

2,651

 

500

 

1,023

 

1,522

 

21,485

 

13,675

 

35,160

 

2,292

 

1,397

 

3,689

Economic Factors

 

64

 

(109)

 

(45)

 

127

 

25

 

152

 

(84)

 

(71)

 

(155)

 

(99)

 

(95)

 

(194)

Technical Revisions

 

1,007

 

(735)

 

272

 

(437)

 

(1,468)

 

(1,906)

 

7,236

 

(11,073)

 

(3,836)

 

232

 

(1,739)

 

(1,507)

Production

 

(1,823)

 

-

 

(1,823)

 

(1,560)

 

-

 

(1,560)

 

(13,144)

 

-

 

(13,144)

 

(1,570)

 

-

 

(1,570)

December 31, 2018

 

9,637

 

3,024

 

12,660

 

21,181

 

7,215

 

28,395

 

106,530

 

60,631

 

167,160

 

13,783

 

7,277

 

21,060

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional Natural Gas

 

Shale Gas

 

Total

 

 

 

 

 

 

 

Proved

 

 

 

 

Proved

 

 

 

 

Proved

TOTAL

 

 

 

 

 

Plus

 

 

 

 

Plus

 

 

 

 

Plus

Factors

 

Proved

Probable

Probable

Proved

Probable

Probable

Proved

Probable

Probable

 

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MMcf)

    

(MBOE)

    

(MBOE)

    

(MBOE)

December 31, 2017

 

55,992

 

21,289

 

77,281

 

803,018

 

233,742

 

1,036,760

 

278,712

 

118,737

 

397,448

Acquisitions

 

 -

 

 -

 

 -

 

114

 

26

 

139

 

217

 

48

 

265

Dispositions

 

(6,447)

 

(2,293)

 

(8,741)

 

(126)

 

(37)

 

(162)

 

(1,433)

 

(496)

 

(1,929)

Discoveries

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

Extensions and Improved Recovery

 

976

 

395

 

1,372

 

77,554

 

70,598

 

148,152

 

38,866

 

29,077

 

67,943

Economic Factors

 

(1,597)

 

(1,523)

 

(3,120)

 

(1,240)

 

549

 

(691)

 

(465)

 

(413)

 

(878)

Technical Revisions

 

(8,602)

 

(7,739)

 

(16,341)

 

54,558

 

(4,430)

 

50,129

 

15,697

 

(17,043)

 

(1,346)

Production

 

(9,314)

 

-

 

(9,314)

 

(84,814)

 

-

 

(84,814)

 

(33,785)

 

-

 

(33,785)

December 31, 2018

 

31,007

 

10,129

 

41,137

 

849,063

 

300,449

 

1,149,511

 

297,809

 

129,909

 

427,718

 

 

 

UNDEVELOPED RESERVES 

 

The following tables disclose the volumes of proved undeveloped reserves and probable undeveloped reserves of the Corporation that were first attributed in the years indicated.

 

Proved Undeveloped Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

 

 

 

 

 

 

 

 

    

 

    

 

    

 

    

 

    

Conventional

    

 

    

 

 

 

Light &

 

 

 

 

 

 

 

Natural

 

Shale

 

 

Year (1)

 

Medium

 

Heavy

 

Tight

 

NGLs

 

Gas

 

Gas

 

Total

 

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(MMcf)

 

(MMcf)

 

(MBOE)

2016

 

100

 

-

 

3,492

 

391

 

-

 

6,080

 

4,996

2017

 

354

 

390

 

19,113

 

2,170

 

28

 

52,296

 

30,749

2018

 

450

 

500

 

17,345

 

1,725

 

 -

 

64,895

 

30,835

 

Note:  

(1) First attributed volumes include additions during the year and do not include revisions to previous undeveloped reserves.

 

Probable Undeveloped Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional

 

 

 

 

 

    

Light &

    

 

    

 

    

 

    

Natural

    

Shale

    

 

Year (1)

 

Medium

 

Heavy

 

Tight

 

NGLs

 

Gas

 

Gas

 

Total

 

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(MMcf)

 

(MMcf)

 

(MBOE)

2016

 

45

 

-

 

13,104

 

1,468

 

-

 

26,468

 

19,028

2017

 

163

 

165

 

14,891

 

1,645

 

12

 

37,251

 

23,075

2018

 

205

 

1,023

 

12,650

 

1,258

 

35

 

69,512

 

26,727

 

Note:

(1)   First attributed volumes include additions during the year and do not include revisions to previous undeveloped reserves.

28      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

The Corporation attributes proved and probable undeveloped reserves based on accepted engineering and geological practices as defined under NI 51-101. These practices include the determination of reserves based on the presence of commercial test rates from either production tests or drill stem tests, extensions of known accumulations based upon either geological or geophysical information, and the optimization of existing fields. The Corporation considers each of its undeveloped locations to be projects that have larger capital expenditures and, consistent with the COGE Handbook, has generally assigned development of or the commencement of significant capital spending on proved undeveloped locations to occur within three years (five years for resource plays) and within five years (ten years for resource plays) for probable undeveloped reserves. The Corporation has in recent years continually developed its undeveloped reserves in Canada and the United States. The Corporation intends to fund the development of its undeveloped reserves as of December 31, 2018 with cash,  internally generated cash flow and/or debt. These expenditures are expected to extend the continual development of undeveloped reserves in Canada and the United States beyond two years.

 

In the Fort Berthold property, the Corporation has been active for the last several years in drilling and developing these undeveloped reserves, converting the associated volumes to producing reserves. The Corporation has, in the past, maintained the gross proved plus probable undeveloped location well count year over year and added undeveloped locations to replace those that were drilled in the preceding year. The Corporation expects to increase its activity in Fort Berthold and has increased the gross proved plus probable undeveloped location count from 130 locations in 2017 to 151  locations as of December 31, 2018. The conversion of the proved undeveloped locations to producing reserves is scheduled to occur continuously over the next three years and the development of the remaining probable undeveloped locations is scheduled to occur within four years.

 

In 2018, the Corporation continued to participate in the development of its non-operated undeveloped reserves in the Marcellus property, converting 6.2 net proved plus probable locations to developed reserves. These converted locations were replaced with additions of 8.3 net proved plus probable undeveloped locations as of December 31, 2018. Development timing for both proved undeveloped and proved plus probable undeveloped locations is determined by the scheduling prepared by the operators of the property. In this case, development of both the proved undeveloped and probable undeveloped locations is scheduled in each of the next five years.

 

In Canada, the Corporation’s drilling activity level has been modest in recent years, and in 2018 consisted of drilling four gross proved plus probable undeveloped locations in Medicine Hat Glauc C   and two gross proved plus probable undeveloped locations in the Ratcliffe property. Additional proved plus probable undeveloped locations were assigned in Giltedge (four gross), Medicine Hat Glauc C (five gross) and Ratcliffe (one gross) as of December 31, 2018. In addition to these properties, there are also undeveloped reserves assigned in the Cadogan property.  Enerplus anticipates  there will be drilling activity in these four properties starting in 2019. Development of the Canadian proved undeveloped reserves is forecast to occur continuously over the next two years, and the development of the probable undeveloped reserves is forecast to occur over the next four years.

 

SIGNIFICANT FACTORS OR UNCERTAINTIES 

 

Changes in future commodity prices relative to the forecasts described above under " Forecast Prices and Costs " could have a negative impact on the Corporation's reserves and, in particular, on the development of undeveloped reserves, unless future development costs are adjusted in parallel. Other than the foregoing and the factors disclosed or described in the tables above, the Corporation does not anticipate any other significant economic factors or other significant uncertainties which may affect any particular components of its reserves data.

 

In connection with its operations, the Corporation will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. The Corporation budgets for and recognizes as a liability the estimated present value of the future decommissioning liabilities associated with its property, plant and equipment. There are no unusually significant abandonment and reclamation costs associated with its reserves properties or properties with no attributed reserves, and the Corporation does not anticipate its abandonment and reclamation liabilities to negatively impact its reserves data or its ability to develop these reserves at this time.

 

For further information, see " Risk Factors – The Corporation's actual reserves and resources   will vary from its reserves and resources estimates, and those variations could be material " and “ – Recent court rulings on the liability surrounding abandonment and reclamation obligations of oil and gas companies may adversely affect the Corporation”.

 

PROVED AND PROBABLE RESERVES NOT ON PRODUCTION

 

The Corporation has approximately 3.4 MMBOE of proved plus probable reserves which are capable of production but which, as of December 31, 2018, were not on production. These reserves have generally been non‑producing for periods ranging from a few months to more than five years. In Canada, the majority of these reserves are related to reserves volumes associated with shut-in sour gas wells in Ferrier, which are to be tied-in to a different processing facility, and incremental polymer flood volumes in Giltedge. In the United States, the majority of these volumes are associated with non-operated wells drilled in 2018 in North Dakota that have not commenced production, and operated wells in Montana that

ENERPLUS 2018 ANNUAL INFORMATION FORM     29

 

 

are shut-in due to pump failures. All of these non-producing assets have been scheduled to recommence production in 2019 or 2020.

 

 

Supplemental Operational Information

SAFETY AND SOCIAL RESPONSIBILITY

 

The Corporation has adopted a Safety and Social Responsibility Policy (the “ S&SR Policy ”), which articulates its commitment to health and safety, environmental, stakeholder engagement, and regulatory compliance. The S&SR Policy applies to any activities undertaken by or on behalf of the Corporation in its operating areas. The Corporation’s board of directors and the President & Chief Executive Officer are ultimately accountable for ensuring compliance with the S&SR Policy. The Corporation’s management and its Safety & Social Responsibility department are responsible for ensuring that the S&SR Policy is implemented and communicated across the Corporation. All employees and contractors of the Corporation are responsible for complying with the S&SR Policy. The Safety & Social Responsibility Committee of the Corporation’s board of directors (the “ S&SR Committee ”) is responsible for overseeing the Corporation’s S&SR performance and ensuring there are adequate systems in place   to support ongoing compliance, and to plan and execute the Corporation’s activities in a safe and socially responsible manner.

 

The Corporation strives to develop and operate its oil and natural gas assets in a socially responsible manner and places a high priority on protecting the health and safety of its employees, contractors, and the public in the communities in which it operates, as well as preserving the quality of the environment. The Corporation also encourages active and open collaboration with its stakeholders. The Corporation has established processes and programs designed to evaluate and minimize health, safety, and environmental risks, and strives for continuous improvement in its S&SR performance. The Corporation also actively participates in industry recognized programs, as well as certain international best practices, which support its sustainability goals. 

 

The S&SR Policy discusses the Corporation's commitment to protect the health and safety of all persons and communities involved in, or affected by, its business activities. Specifically, the S&SR Policy outlines that the Corporation will:

·

promote and support a culture in which all employees and contractors share ownership of a workplace where no one gets injured

·

provide the resources, equipment and training needed to ensure everyone complies with its health and safety programs

·

strive to continually improve its safety culture by integrating applicable industry best practices and operational experience into its health and safety mindset and programs

 

The S&SR Policy also states the Corporation's commitment to the environment and states that the Corporation will:

·

proactively manage its impact on the environment and consider innovative improvement opportunities

·

work to reduce its environmental impact in the areas in which it operates, including reviewing the efficiency of its energy consumption to reduce emissions intensity

·

improve its water and land use practices

·

limit the waste it generates

·

prevent and manage environmental releases

·

provide transparent disclosure

·

provide resources and training to meet its environmental commitments

 

The Corporation's commitment to building meaningful and transparent relationships with its stakeholders is embedded in its S&SR Policy. In addition, the S&SR Policy expresses the Corporation’s commitment to engaging with stakeholders to promote economic and social development for the people and communities in its operating areas.

 

Finally, the Corporation’s commitment to the responsible development of resources and regulatory compliance is stated in its S&SR Policy and Corporate Sustainability Report (the “ Report ”), which the Corporation publishes annually in accordance with the Global Reporting Initiative international standard. The Report summarizes the Corporation’s environmental, safety, social responsibility and governance performance, and can be found at www.enerplus.com.

 

Health and Safety

 

The Corporation's combined (employee/contractor) recordable injury frequency rate for 2018 was 1.13 injuries per 200,000 man hours, a decrease from the rate of 1.63 recorded in 2017. The Corporation's employee recordable injury frequency rate of 0.24 injuries per 200,000 man hours in 2018 was in line with 0.23 injuries per 200,000 man hours in 2017. The Corporation's total contractor recordable injury frequency of 1.53 injuries per 200,000 man hours in 2018 decreased from 2.64 injuries per 200,000 man hours in 2017. The Corporation recorded six lost-time injuries in 2018, an increase from three recorded in 2017. The Corporation has not had employee or contractor fatalities for any of the last five years .

30      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

 

Health and safety risks influence workplace practices, operating costs, and the establishment of regulatory standards. The Corporation maintains a health and safety management system designed to:

·

increase emphasis on safety awareness and promote continuous improvement and safety excellence

·

provide staff with the training and resources needed to complete work safely

·

incorporate hazard assessment and risk management as an integral part of everyday business

·

monitor performance to ensure that its operations comply with all legal obligations and its internally‑imposed standards

 

The health and safety component of the S&SR management system is reviewed annually for continuous improvement opportunities. The Corporation continues to develop and implement prevention measures and safety management program improvements to support its focus and commitment for an injury‑free workplace.

 

Environment 

 

The Corporation’s operations are subject to applicable laws and regulations relating to the environment. See “ Industry Conditions – Environmental Regulation ”. The Corporation is committed to meeting its responsibilities to protect the environment through a variety of programs and actively monitors its operations for compliance with all relevant and applicable environmental regulations and industry best practices. The Corporation engages in the following activities:

 

·

Site abandonment and reclamation capital expenditures for the Corporation's Canadian and United States properties in 2018 totaled approximately $11.3 million ($9.2 million on operated properties and $2.1 million on non‑operated properties). The Corporation received 19 reclamation certificates from regulatory agencies in 2018 by returning sites to their previous equivalent land capability.

 

·

The Corporation undertakes third-party environmental compliance audits designed to ensure compliance with environmental legislation and regulations. In 2018, three environmental compliance audits were completed.

 

·

The Corporation commissions third-party loss prevention audits to identify and evaluate the risk exposures associated with production equipment, process operations, utility supply systems and natural hazards. The purpose of the loss prevention audits is to generate detailed loss prevention reports with risk-based recommendations for improving the overall safety and performance of the Corporation’s facilities, mitigating the potential exposure to financial loss associated with property damage and production loss, and ensuring the adequacy of its relevant insurance coverage. Two loss prevention audits occurred in 2018.

 

·

Government regulators conducted 124 inspections of the Corporation’s field operations in the United States and Canada in 2018, a reduction compared to the prior year’s 235 government regulator inspections. The percentage of non-compliant field inspections received by the Corporation in 2018 was 9%, compared to the 12% received in 2017. However, the Corporation continued its internal facility inspection program and completed 19 inspections at major Canadian facilities in 2018. The average score of compliance resulting from the internal inspection program in 2018 was 91%, in line with the result of 92% in 2017.

 

·

The Corporation conducts an internal site inspection program at its U.S. and Canadian locations to proactively assess environmental, regulatory and general housekeeping items. Findings from the internal site inspection program and any action items are recorded in the Corporation’s internal Sustainability Information Management System in order to measure compliance and ensure potential issues are addressed.

 

·

The Corporation conducts annual property reviews with specific risk reduction objectives. The Corporation also continues to manage risk through its ongoing pipeline risk assessment process and various other activities, such as inspections of pipelines at water crossings. The Corporation reviews each of its pipeline systems annually. The Corporation continues to incorporate improvements to these programs, which are designed to identify and mitigate significant risks, and to decrease the number and severity of pipeline failure incidents.

 

·

The Corporation has estimated its direct emissions in 2018 to be approximately 796,499 carbon dioxide equivalent tonnes per year, which is 38% more   than the Corporation's direct emissions in 2017 of 575,704 carbon dioxide equivalent tonnes per year. The increase was a result of the growth in liquids production during 2018 .   The estimated numbers will be confirmed as additional data becomes available. The Corporation does not expect to incur additional costs as a result of the emissions increases as it is in compliance with all relevant gas capture requirements.

 

·

In 2018, the Corporation completed a total of 348 fugitive emissions surveys for its Canadian facilities and U.S. production pad facilities to detect losses from leaks and vents, and is working to repair all identified leaks. The Corporation does not expect the cost to remedy the leaks to be material.

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     31

 

 

Greenhouse gas (“ GHG ”) regulations have been enacted in British Columbia, Alberta and at the federal level in Canada and the United States. In 2018, the Corporation’s only area subject to active carbon tax regulations affecting its operations was in the jurisdiction of British Columbia. The total carbon tax paid was approximately $0.6   million in 2018. In addition, the Corporation is required to report third-party verified GHG emissions annually to the government of British Columbia pursuant to the Greenhouse Gas Emission Reporting Regulation (the “ Reporting Regulation ”) enacted under the Greenhouse Gas Industrial Reporting and Control Act .  In 2018, the Corporation was not subject to any Canadian federal greenhouse gas emissions reporting requirements as it did not operate facilities above the 10,000 tonnes of carbon dioxide equivalent (“ CO 2e “) per year, per facility threshold (the limit which came into effect in 2017). For its operations in the United States, the Corporation is subject to the reporting requirement under the U.S. Environmental Protection Agency (the “ U.S.   EPA ”) Clean Air Act and the Mandatory Reporting of Greenhouse Gases Rule. The latest of these reports was submitted to the U.S. EPA on March 31, 2018 for the 2017 operational year. For more information on the environmental regulation applicable to the Corporation, see " Industry Conditions – Environmental Regulation” .

 

The S&SR Committee regularly reviews health, safety, environmental and regulatory updates, and risks. At present, the Corporation believes it is, and expects to continue to be, in compliance with all material applicable environmental laws and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet its ongoing environmental obligations.

 

Overall, the Corporation strives to operate in a socially responsible manner and believes its health, safety and environmental initiatives and performance confirm its ongoing commitment to environmental stewardship and the health and safety of its employees, contractors, and the general public in the communities in which it operates. Annually, the Corporation identifies key S&SR focus areas to support this commitment and sets forth strategic targets. The Corporation believes that by monitoring S&SR lagging and leading metrics, identifying areas for improvement, and implementing strategies, processes and procedures in those key focus areas, the Corporation will continue to improve its S&SR performance.

 

INSURANCE

 

The Corporation carries insurance coverage to protect its assets at the standards typical within the oil and natural gas industry. Insurance levels are determined and acquired by the Corporation after considering the perceived risk of loss and appropriate coverage, together with the overall cost. The Corporation currently purchases insurance to protect against a number of risks including, but not limited to, third party liability, property damage, business interruption, terrorism, pollution and well control. In addition, liability coverage is also carried for the directors and officers of the Corporation.

 

PERSONNEL

 

As at December 31, 2018, the Corporation employed a total of 399 persons, including full‑time benefit employees and payroll consultants, 254   of whom were in Canada and 145 of whom were in the United States.

 

32      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

Description of Capital Structure

 

The authorized capital of the Corporation consists of an unlimited number of Common Shares, and a number of preferred shares issuable in series (" Preferred Shares "), which are limited to an amount equal to not more than one‑quarter of the number of issued and outstanding Common Shares at the time of the issuance of any such Preferred Shares. The following is a summary of the rights, privileges, restrictions and conditions attaching to the Common Shares and the Preferred Shares. Copies of the Corporation's Articles, By-law No. 1 and By-law No. 2 were filed on January 2, 2013, June 16, 2014, and May 6, 2016, respectively, on the Corporation's SEDAR profile at  www.sedar.com and on the Corporation's EDGAR profile at  www.sec.gov .

 

COMMON SHARES

 

Holders of Common Shares are entitled to receive notice of and to attend all meetings of shareholders of the Corporation and to one vote at such meetings for each Common Share held. The holders of the Common Shares are, at the discretion of the Corporation's board of directors and subject to applicable legal restrictions and subject to the rights, privileges, restrictions and conditions attaching to any other class or series of shares of the Corporation, entitled to receive any dividends declared by the Corporation on the Common Shares and to share in the remaining property of the Corporation upon liquidation, dissolution or winding‑up.

 

The Articles contain provisions facilitating payment of dividends on Common Shares through issuance of Common Shares in circumstances where the board of directors declares, and a shareholder of the Corporation validly elects to receive, the payment of dividends, in whole or in part, in the form of Common Shares. See " Dividends – Stock Dividend Program ". 

 

PREFERRED SHARES

 

There are no Preferred Shares outstanding as of the date of this Annual Information Form. Preferred Shares may be issued from time to time in one or more series with such rights, restrictions, privileges, conditions and designations attached thereto as shall be fixed from time to time by the Corporation's board of directors. Subject to the provisions of the ABCA, the Preferred Shares of each series shall rank in parity with the Preferred Shares of every other series. The Preferred Shares shall be entitled to preference over the Common Shares and any other shares of the Corporation ranking junior to the said Preferred Shares with respect to payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding‑up of the Corporation, whether voluntary or involuntary, to the extent fixed in the case of each respective series, and may also be given such other preferences over the Common Shares and any other shares of the Corporation ranking junior to the said Preferred Shares as may be fixed in the case of each such series.

 

SHAREHOLDER RIGHTS PLAN  

 

The continuation and amendment and restatement of the Shareholder Rights Plan was approved by shareholders of the Corporation, including by  a requisite number of the Corporation's "Independent Shareholders" (as defined in the Shareholder Rights Plan), at the annual meeting held on May 6, 2016. The continuation of the Shareholder Rights Plan must next be approved by the Corporation's "Independent Shareholders" at the annual meeting of shareholders of the Corporation to be held on May 9, 2019, failing which it will expire at the end of such meeting. The Corporation has no intention to renew the Shareholder Rights Plan at the annual meeting of shareholders in 2019. As such, the Shareholder Rights Plan will expire in accordance with its terms on May 9, 2019.

ENERPLUS 2018 ANNUAL INFORMATION FORM     33

 

 

SENIOR UNSECURED NOTES

 

Enerplus has issued Senior Unsecured Notes, of which US$489 million and CDN$30 million principal amounts were outstanding at December 31, 2018. Certain terms of the Senior Unsecured Notes are summarized below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Original

 

Remaining

 

Coupon

 

Interest

 

 

 

 

Issue Date

   

Principal

   

Principal

   

Rate

    

Payment Dates

   

Maturity Date

   

Term

September 3, 2014

 

US$200 million

 

US$105 million

 

3.79

%  

March 3 and September 3

 

September 3, 2026

 

Principal payments required in five equal annual installments beginning September 3, 2022

May 15, 2012

 

CDN$30 million

 

CDN$30 million

 

4.34

%  

May 15 and November 15

 

May 15, 2019

 

Bullet payment on maturity

May 15, 2012

 

US$20 million

 

US$20 million

 

4.40

%  

May 15 and November 15

 

May 15, 2022

 

Bullet payment on maturity

May 15, 2012

 

US$355 million

 

US$298 million

 

4.40

%  

May 15 and November 15

 

May 15, 2024

 

Principal payments required in five equal annual installments beginning May 15, 2020

June 18, 2009

 

US$225 million

 

US$66 million

 

7.97

%  

June 18 and December 18

 

June 18, 2021

 

Principal payments required in three equal annual installments beginning June 18, 2019

 

For additional information see " Material Contracts and Documents Affecting the Rights of Securityholders ".  See also Note 7   to the Financial Statements.

 

BANK CREDIT FACILITY

 

As of December 31, 2018, the Corporation was undrawn on its $800 million senior unsecured, covenant‑based credit facility with a syndicate of financial institutions maturing October 31, 2021. 

 

For a description of the Bank Credit Facility, see Note 7   to the Corporation's Financial Statements. See also " Material Contracts and Documents Affecting the Rights of Securityholders ".

 

 

34      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

Dividends

 

DIVIDEND POLICY AND HISTORY

 

The Corporation's board of directors is responsible for determining the dividend policy of the Corporation. The dividend policy must comply with the requirements of the ABCA, including satisfying the solvency test applicable to ABCA corporations. The Corporation currently has established a dividend policy of paying monthly dividends to holders of Common Shares. The dividend record date is on or about the last business day of each calendar month and the corresponding dividend payment date is on or about the 15th day of the following month. However, any decision to pay dividends on the Common Shares will be made by the Corporation's board of directors on the basis of the relevant conditions existing at such future time, and there can be no guarantee that the Corporation will maintain its current dividend policy. Dividend amounts likely will vary, and there can be no assurance as to the level of dividends that will be paid or that any dividends will be paid at all. See " Risk Factors – Dividends and other payments on the Corporation's Common Shares are variable . Monthly cash dividends paid to U.S. resident shareholders are converted to U.S. dollars based upon the actual Canadian to U.S. dollar exchange rate on the dividend payment date and, accordingly, shareholders not resident in Canada are subject to foreign exchange rate risk on such payments.

 

The table below sets forth the dividends paid or declared by the Corporation in 2016,  2017, 2018  and January through March of 2019:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Month

    

2019

    

2018

    

2017

    

2016

January

 

$

0.01

 

$

0.01

 

$

0.01

 

$

0.03

February

 

 

0.01

 

 

0.01

 

 

0.01

 

 

0.03

March

 

 

0.01

 

 

0.01

 

 

0.01

 

 

0.03

April

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

May

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

June

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

July

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

August

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

September

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

October

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

November

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

December

 

 

N/A

 

 

0.01

 

 

0.01

 

 

0.01

 

For certain tax information relating to the dividends paid on the Common Shares for Canadian and U.S. federal income tax purposes, please refer to the Corporation's website at  www.enerplus.com .

 

Shareholders are advised to consult their tax advisors regarding questions relating to the tax treatment of dividends paid by the Corporation. For additional information on potential risks associated with the taxation of dividends paid by the Corporation, see " Risk Factors ".

 

STOCK DIVIDEND PROGRAM

 

Effective May 11, 2012, the Corporation implemented a stock dividend program pursuant to which shareholders of the Corporation were able to elect to receive dividends in the form of Common Shares, instead of receiving a cash dividend, issued at a deemed price of 95% of the five-day weighted average trading price of the Common Shares on the TSX immediately prior to the applicable dividend payment date. Effective with the April 2014 dividend, the Corporation elected to eliminate the 5% discount applied to determine the number of Common Shares issued pursuant to the stock dividend program. Effective September 19, 2014, the board of directors of the Corporation suspended the stock dividend program to eliminate the dilution associated with the issuance of Common Shares through the program.  

 

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     35

 

 

Industry Conditions

 

OVERVIEW  

 

The Corporation, and the oil and natural gas industry generally, are subject to extensive controls and regulation governing operations (including land tenure, exploration, development, production, refining, transportation, marketing, remediation, abandonment and reclamation) imposed by legislation enacted by various levels of government. The Corporation and the oil and natural gas industry are also subject to agreements among the various federal, state and provincial governments with respect to pricing and taxation of oil and natural gas. Although it is not expected any of these controls, regulations or agreements will affect the Corporation's operations in a manner materially different than they would affect other oil and gas producers in similar operating areas, the controls, regulations and agreements should be considered carefully by investors in the oil and gas industry. All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the Corporation’s participation in the oil and gas industry that are applicable to the Corporation’s operations.

 

The Corporation owns oil and natural gas properties and related assets in the United States (Montana, North Dakota, Pennsylvania and Colorado) and Canada (Alberta, Saskatchewan and British Columbia). The Corporation's oil and natural gas operations are regulated by a wide range of administrative agencies under statutory provisions of the states and provinces where such operations are conducted, by certain agencies of the federal government for operations on U.S. federal leases and, in some cases, by local agencies. These provisions regulate matters such as the exploration for and production of crude oil and natural gas, including rules related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the abandonment of wells. The Corporation's operations are also subject to various conservation laws and regulations in respect of matters such as the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil and natural gas properties. In addition, conservation laws sometimes establish maximum rates of production from crude oil and natural gas wells, generally prohibit or limit the venting or flaring of natural gas and associated liquids, and impose certain requirements regarding the rateability or fair apportionment of production from fields and individual wells. As well, the Corporation is required to disclose payments made to governments of all levels,   including First Nations in Canada and Indian Reservations in the United States, as part of a transparency reporting initiative legislated by the Canadian government . 

 

PRICING AND MARKETING OF CRUDE OIL AND NATURAL GAS

 

In the United States and Canada, producers of crude oil negotiate sales contracts directly with crude oil purchasers. Most agreements are linked to continental or global oil prices, which are set by daily, weekly and monthly physical and financial transactions for crude oil around the world. Those prices are primarily based on overall fundamentals of supply and demand. Specific prices depend, in part, on crude oil quality, prices of competing fuels, distance to markets, access to downstream transportation, the value of refined products, the supply/demand balance and other contractual terms. 

 

Producers of natural gas in the United States and Canada are free to negotiate prices and other terms with purchasers, provided export contracts meet certain criteria. In relation to U.S. exports, this would include restrictions on export licenses imposed by the United States Department of Energy, and in Canada, criteria prescribed by the National Energy Board and the Government of Canada. The prices depend, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to the market, access to downstream transportation, length of contract term,  seasonal factors, weather conditions, the value of refined products, the supply/demand balance and other contractual terms. In the United States, the Federal Energy Regulatory Commission regulates interstate natural gas rates and service conditions, which affect the marketing of natural gas, as well as revenues producers receive for sales of natural gas. Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies. 

 

Internationally, prices for crude oil and natural gas fluctuate in response to changes in the supply and demand for crude oil and natural gas, market uncertainty, and a variety of other factors beyond the Corporation's control.  Crude oil and natural gas prices have experienced significant volatility in response to a variety of factors including, among others, the increase in the global supply of crude oil and the ongoing decisions by the Organization of Petroleum Exporting Countries (“ OPEC ”) and non-OPEC members, including Canada, to manage production levels to achieve  balance in crude oil supply and demand.  See " Risk Factors – Oil and natural gas prices are volatile. An extended period of low oil and natural gas prices could have a material adverse effect on the Corporation's business, results of operations or cash flows and financial condition ". In addition, crude oil and natural gas producers in some areas of North America, such as Alberta, currently receive significantly discounted prices for their production relative to certain continental and/or international benchmark prices due to the lack of adequate egress which would allow crude  oil and natural gas production to be transported and sold to national and, in some cases, international markets.  See " Risk Factors –   Lack of adequately developed infrastructure, and the impact of special interest groups on such development, may result in a decline in the Corporation's ability to market its oil and natural gas production ". 

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ROYALTIES AND INCENTIVES 

 

In addition to federal regulations, each province in Canada and each U.S. state has legislation and regulations which govern oil and gas holdings and land tenure, royalties, production rates, environmental protection and other matters. In all Canadian jurisdictions, producers of oil and natural gas are required to pay annual rentals and royalties in respect of Crown leases, and royalties and freehold production taxes in respect of oil and natural gas produced from freehold lands. In all U.S. jurisdictions, producers of oil and natural gas are typically required to make annual rental payments in respect of federal, state and freehold leases until production begins. Upon commencement of production, royalties and production taxes are paid in respect of oil and natural gas produced from federal, state and freehold lands. Producers on U.S. Indian leases are required to make annual rental payments regardless of well production, in addition to other fixed fees for land improvement, on a per well basis. The applicable royalty and production tax regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown‑owned lands in Canada and federal and state lands in the U.S. are determined by negotiations between the freehold mineral owner and the lessee. Crown royalties in Canada, and federal, U.S. Indian, and state royalties and production taxes in the U.S., are determined by government regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. Other royalties and royalty‑like interests are from time to time carved out of the working interest owner's interest through non‑public transactions. These are often referred to as overriding royalties, gross overriding royalties or net profits or net carried interests.

 

From time to time, the federal and provincial governments in Canada and the federal and state governments in the U.S. have established incentive programs which have included royalty rate or production tax reductions (including for specific wells), royalty holidays, and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects. If applicable, oil and natural gas royalty holidays, reductions and tax credits would effectively reduce the amount of royalties paid by oil and gas producers to the applicable governmental entities.

 

LAND TENURE 

 

Crude oil and natural gas located in the western Canadian provinces are owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying periods and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned, 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.

 

Crude oil and natural gas located in the U.S. is predominantly owned by private owners. The U.S. Department of the Interior - Bureau of Land Management (" BLM "), and the state in which the minerals are located also may hold ownership to such rights. These owners, from governmental bodies to private individuals, grant rights to explore for and produce oil and gas pursuant to leases, licenses and permits for varying periods and on conditions including requirements to perform specific work or make payments. As to those rights held by private owners, all terms and conditions may be negotiated. For those rights held by governmental agencies, typically the terms and conditions of the oil and gas lease have been predetermined by each governing or regulatory body. Substantially all of the leaseholds currently owned by the Corporation in the U.S. have been granted through private individuals.

 

The majority of the Corporation's operations in North Dakota take place on the Fort Berthold Indian Reservation (" FBIR ") and involve allotee lands, which are lands that are administered by the Bureau of Indian Affairs (" BIA ") but owned by individual band members. As such, these operations are governed by both state and federal regulations. U.S. federal departments such as the BIA, the BLM, and the U.S. EPA enforce the federal regulations. Federal U.S. regulations may differ significantly from regulations generally applicable to non‑federally regulated lands and, as a consequence, may result in the slowing, or halting of, the Corporation's developments on the FBIR.

 

A lease generally may be continued after the initial term provided certain minimum levels of exploration or production have been achieved and all lease rentals have been timely paid, subject to certain exceptions. To develop minerals, including oil and natural gas, it is necessary for the mineral estate owner to have access to the surface estate. Under common law, the mineral estate is considered the "dominant" estate with the right to extract minerals subject to reasonable use of the surface. Each jurisdiction has developed and adopted its own statutes that operators must follow both prior to and following drilling, including notification requirements and the obligation to provide compensation for lost land use and surface damage. The surface rights required for pipelines and facilities are generally governed by leases, easements, rights‑of‑way, permits or licenses granted by landowners or governmental authorities.

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ENVIRONMENTAL REGULATION    

 

The Corporation is subject to the applicable municipal, provincial, state and federal environmental laws and regulations in its operating areas in both Canada and the U.S. These requirements provide for environmental protection and impose restrictions and prohibitions regarding disturbances and releases or emissions of various substances produced or utilized in association with oil and gas industry operations. With respect to a property designated as a contaminated site, environmental laws may impose remediation obligations upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused release of the substance, and any past or present owner, tenant, or other person in possession of the site. In addition, legislation requires that well, pipeline and facility sites are abandoned and reclaimed to the satisfaction of the applicable authorities. Compliance with these requirements can involve significant expenditures. A breach of such requirements may result in the imposition of material fines and penalties, the suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, or the issuance of clean‑up orders. See “ Risk Factors – The Corporation's operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities, including those related to climate change,   as well as public opposition and activism ”.

 

British Columbia

 

In British Columbia, all oil and gas operations, including exploration, development, pipeline transportation and reclamation, are overseen by the British Columbia Oil and Gas Commission (“ BCOGC ”), primarily through the Oil and Gas Activities Act . The BCOGC also oversees compliance with a variety of environmentally-related statutes, including the Forest Act ,   Heritage Conservation Act ,   Land Act ,   Environmental Management Act and the Water Sustainability Act . 

 

Alberta

 

In Alberta, the Alberta Energy Regulator (“ AER ”) is the single regulator of energy development in Alberta and oversees all aspects of the regulatory process, including application and exploration, construction and development, abandonment, reclamation, and remediation activities. The AER oversees compliance with the Oil and Gas Conservation Act ,   Public Lands Act and the Mines and Minerals Act, the Water Act and the Environmental Protection and Enhancement Act by oil and gas operators.

 

Saskatchewan

 

In Saskatchewan, oil and gas exploration is overseen by the Ministry of Energy and Resources which administers legislation including The Crown Minerals Act, The Oil and Gas Conservation Act and The Pipelines Act, 1998 . Environmental regulation is governed by the Ministry of Environment pursuant to the Saskatchewan Environmental Code , which consolidates rules under other statutes and, among other things, prescribes applicable levels of emissions without mandating express measures to achieve such levels.

 

United States

 

In the United States, oil and gas operations are regulated at the federal, state, county, and tribal levels of government. At the federal level, well planning and permitting is primarily regulated by the BLM   and the BIA for operations on public and tribal lands under the Federal Land Policy and Management Act and the National Environmental Policy Act . Environmental conservation and cultural and natural resources protection at the federal level are administered by numerous agencies under multiple statutes.

 

Planning, permitting and compliance related to environmental media protection and contaminants at the federal level are administered by the U.S. EPA, or by various states whose programs have been granted primacy by the U.S. EPA. The U.S. EPA governs federal legislation, including the Clean Air Act , the Clean Water Act , the Resource Conservation and Recovery Act (other than oil and gas exempt wastes), the Comprehensive Environmental Response, Compensation and Liability Act , the Oil Pollution Act , the Emergency Planning and Community Right‑to‑Know Act and the Safe Drinking Water Act and Federal Executive Orders.

 

The Corporation’s U.S. operations are subject to various regulations, including those relating to well permits, linear facilities, hydraulic fracturing, underground injection, and setbacks (buffers) for environmental protection, which are imposed by several state agencies regulating oil and gas activities. In addition to the agencies which directly regulate oil and gas operations, there are other state and local conservation and environmental protection agencies that regulate air quality, water quality, aquatic biology, wildlife, visual quality, transportation, noise, spills and incidents and transportation.

 

Additional regulations affecting the Corporation's U.S. operations include: (i) the Federal Implementation Plan for Oil and Natural Gas Well Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa, and Arikara Nations) (the “ MHA Nation ”), in North Dakota and (ii) the Standards of Performance for Crude Oil and Natural Gas Production, Transmission

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and Distribution. These regulations provide emission control requirements for the Corporation's U.S. assets, as well as increased monitoring, recordkeeping, reporting and regulatory oversight.

 

At the request of Congress, in 2011 the U.S. EPA began research under its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources . The purpose of the study was to assess the potential impacts of hydraulic fracturing on drinking water resources, and to identify the driving factors that may affect the severity and frequency of such impacts. The U.S. EPA published the final report in December 2016.  The report did not identify systemic or widespread impacts to groundwater from hydraulic fracturing. There have been no further government actions or regulations as of the date of this Annual Information Form.  

 

All U.S. states in which the Corporation operates have regulations on hydraulic fracturing disclosure. The Corporation utilizes the internet‑based chemical registry FracFocus both in Canada and the U.S. for posting of the required disclosure information.  In the U.S., FracFocus is operated by the Ground Water Protection Council, a group of state water officials, and the Interstate Oil and Gas Compact Commission, an association of oil and gas producing states. The online registry was created in 2011, in response, at least in part, to concerns from landowners about the chemical content of fracturing fluids that were being injected into oil and gas wells on their land as well as adjacent properties. FracFocus is widely accepted among the oil and gas industry, and the Corporation utilizes the registry in all states and provinces in which it operates. Currently, FracFocus lists over 700 companies as registry participants.

 

In 2016, the U.S. EPA finalized three air quality regulations potentially affecting the Corporation’s operations. Two of the regulations are related to administrative permitting actions, which pose no additional operational costs for the Corporation. The third rule sets out additional emission control requirements for oil and gas sources. While the Corporation is now largely in compliance with these additional emission control requirements, there may be a risk of non-compliance when the rule is promulgated as final.

 

The BLM, which regulates oil and gas operations located on federal and tribal lands, including the Corporation’s Fort Berthold operations, published its final hydraulic fracturing rules on March 26, 2015. Certain industry participants have objected to the proposed rules on various bases. On June 21, 2016, a federal District Court struck down the rules, concluding that the BLM had exceeded its regulatory authority with the new rules. BLM has filed an appeal to the decision, which is currently ongoing.  

 

In July of 2014, the North Dakota Industrial Commission (“ NDIC ”) finalized a rule that imposes restrictions on the flaring of gas. The rule establishes gas capture rates that must be met by operators to avoid the imposition of crude oil production curtailments. These gas capture rates went into effect in October 2014, and gas capture efficiencies have increased per the required timelines set out by the NDIC. The need for an operator to flare gas primarily stems from the fact that the rate of oil and gas development in North Dakota currently outpaces the construction of gas gathering and processing infrastructure. This situation is the result of various factors, including delays in obtaining right of way approvals, which is particularly cumbersome with respect to operations taking place on FBIR due to the application of additional regulatory requirements. The Corporation is working diligently with its midstream partner and the regulators to expand gas gathering capacity and increase gas capture rates. One measure being taken is the installation of NGL processing skids which are being used to extract NGLs from gas that would have otherwise been flared. See “ Risk Factors -   Higher than expected declines or curtailments in the Corporation’s production due to infrastructure constraints,   third party operational business practices or failures, or government regulation could have an adverse effect on results of operations or cash flows and financial condition ”. The Corporation received no NDIC orders to curtail crude oil production in 2018 and has consistently met or exceeded regulatory established gas capture rates since January 2015. Gas capture requirements were amended, moving to a more stringent 88% in November 2018, with a further increase to 91% by November 2020 under the current NDIC guidelines. The NDIC recently updated their gas capture policy to include additional consideration for gas capture calculations on Tribal land and announced their intention to work with the BLM and the FBIR to defer flaring and gas capture oversight for the FBIR to the MHA Nation in 2019.​ 

 

In December of 2014, NDIC adopted conditioning standards aimed at improving the safety of crude oil when transported. The regulation focuses on ensuring that produced crude oil is sufficiently conditioned at the well site to remove volatility characteristics that might pose unreasonable transportation hazards, regardless of the mode of transportation utilized. The standards, which require quarterly sampling and analysis, became effective during the second quarter of 2015.  The Corporation has been in compliance with the NDIC conditioning standards requirements since their inception and throughout 2018. In January 2019, the NDIC approved revisions to the conditioning standards, reducing the frequency of required sampling and analysis from quarterly to twice per year during the months of October through March.  

 

On November 17, 2016, the BLM finalized new rules on the venting and flaring of produced gas,  which imposed further limits on natural gas flaring, required additional gas leak detection and repair, and provided further clarification on associated royalty obligations. Many of the requirements set out in the rules are duplicative of existing state and U.S. EPA requirements, which are already applicable to and followed by the Corporation. The executive order,   Promoting Energy Independence and Economic Growth ,  issued by the Trump Administration in 2017, resulted in the BLM rescinding many initial requirements of the venting and flaring rules effective November 2018, and largely deferring to state and Tribal regulations. 

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The 2018 Colorado state election resulted in a newly elected state government. The Corporation is working closely with industry partners and trade associations, and building relationships to encourage business certainty and clarity on proposed changes in regulations.  Enerplus’ Colorado operations are subject to stringent regulatory programs and strict enforcement. As a result, active stakeholder engagement and outreach, coupled with implementing a strong regulatory compliance program, are key priorities of the Corporation in 2019 and onward.

 

Implementation of more stringent environmental regulations on the Corporation's U.S. operations could affect the Corporation’s capital and operating expenditures and plans. The Corporation minimizes the potential of these impacts to U.S. operations in many ways, including through participation and membership in trade organizations such as the North Dakota Petroleum Council, Montana Petroleum Association, Independent Petroleum Association of America,   Western Energy Alliance and the Colorado Oil and Gas Association. In addition, the Corporation participates directly in legislative hearings, rulemaking processes, meetings with state officials and local stakeholder groups, and provides both written and verbal comments on proposed legislation and regulations. As in Canada, the Corporation's U.S. operations endeavour to carry out its activities and operations in compliance with all relevant and applicable environmental regulations and good industry practice.

 

Climate change legislation

 

Climate change legislation at each of the provincial, state and federal levels has the potential to significantly affect the oil and gas industry regulatory environment and impose significant financial obligations.

 

Both Canada and the U.S. were part of the United Nations Framework Convention on Climate Change (“ UNFCCC ”) meeting in Paris in 2015. A binding commitment was signed by all panel countries that set a target of no more than a two-degree Celsius warming of the earth based on GHG levels in the atmosphere. This commitment to limit warming may increase provincial, state and federal GHG regulatory rigour as country-level emissions will be reviewed periodically in subsequent meetings to assess alignment with the targets agreed upon. In June of 2017 the U.S. announced its intention to withdraw from the Paris Agreement, delivering written notice of such to the United Nations on August 4, 2017.

 

Although the United States announced its withdrawal from the Paris Agreement, federally the U.S. EPA has issued GHG emissions regulations pursuant to the Clean Air Act that establish a reporting program for CO 2 , methane and other GHG emissions. It has also established a permitting program for certain large GHG emissions sources. While the United States Congress has considered numerous legislative initiatives to reduce or tax GHG emissions, to date no laws in that regard have been enacted. On a state level, some states have enacted laws concerning GHG emissions. However, many of them are being challenged.

 

The Government of Canada is working toward the two-degree target on a sector by sector basis, but has yet to finalize regulations pertaining to the oil and gas sector. As part of its commitment under the Paris Agreement, the Canadian federal government developed the Pan-Canadian Framework on Clean Growth and Climate Change (the “ Framework ”) in 2016, together with provincial (except Saskatchewan, Ontario and Manitoba as these provinces have recently announced their intention to withdraw) and territorial leaders in consultation with Canada’s Indigenous Peoples, to meet Canada’s emission target while enabling economic growth.

 

Under the Framework, the federal government will require all jurisdictions to develop a carbon pricing system that is equivalent to $10 per tonne in 2018 and rising by $10 per year to $50 per tonne in 2022. Jurisdictions can implement: (i) an explicit price-based system (such as the carbon tax adopted by British Columbia or the carbon levy and performance-based emissions system adopted in Alberta), or (ii) a cap-and-trade system (which has been adopted in Ontario and Quebec). Within these programs, provinces have discretion to manage competitiveness of their trade-exposed industries. In June of 2018, the Government of Canada’s federal carbon pricing system, entitled the Greenhouse Gas Pollution Pricing Act (“ GHGPPA ”) received royal assent. The GHGPPA is only intended to act as a regulatory backstop in the event a province or territory does not otherwise implement an adequate GHG regime. It is currently unclear what impact the GHGPPA will have on the Corporations’ operations, particularly in Saskatchewan and Alberta.

 

To complement carbon pricing, the federal government is designing a Clean Fuel Standard with the objective of achieving annual reductions of 30 Mt of GHG emissions by 2030 and driving investment in low carbon fuels. The approach is based on separate life cycle analysis for liquid, gaseous and solid fuels and will not differentiate between crude oil types produced in or imported into Canada. This standard is expected to apply to a broad suite of fuels used in transportation, industry, homes and buildings. The federal government released a Regulatory Design Paper in December of 2018 and final publication of regulations that outlines carbon intensity limits for the liquid fuels stream is expected in 2020, with requirements to be enforced by 2022. Gaseous and solid fossil fuel final regulations are expected in 2021, with requirements to be enforced by 2023. As the standard is still under development, the Corporation is unable to predict the impact it will have. 

 

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The Canadian federal government also issued Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)  (the “ Regulations ”) in April of 2018. The intent of the Regulations is to reduce methane emissions by 40% to 45% below 2012 levels by 2025. These Regulations become applicable in any province or territory that chooses not to develop equivalent regulations. The Regulations have  two stages of implementation:  Stage 1 (leak detection and repair, venting from well completions and compressors), which will be in effect in 2020 and Stage 2 (venting restrictions and pneumatics), which will be in effect in 2023. The Provinces of Alberta, British Columbia, and Saskatchewan are currently seeking equivalency with the federal government and if this is successful, the relevant provincial requirements will be in effect for the Corporation.

 

In 2008, the Province of British Columbia instituted a carbon tax that applies to all fuel users and purchasers in the province. The tax for 2019 is $40 per tonne of CO 2 e , and will increase by $5/tonne annually. Under the Reporting Regulation, facility operators are required to submit third party verified GHG emissions annually to the Province. See " Supplemental Operational Information – Safety and Social Responsibility – Environment ". The Province of British Columbia is in discussions with stakeholders and partners of the Western Climate Initiative to develop a regional cap and trade program. The Corporation is unable to estimate the future potential compliance costs of this program without a carbon price or an allocation of emission allowances. Given the Corporation's current hydrocarbon production levels and lack of development activity in British Columbia in recent years, the Corporation does not expect such costs to be material.

 

Effective January 1, 2017, the Province of Alberta enacted the Climate Leadership Act ,   which imposes a carbon levy on consumers for all GHG emissions arising from the combustion of fuels for heating and transportation. The levy is currently $35 per tonne of CO 2 e emissions, however, oil and gas producers are exempt from this tax for fuel used in a production process until 2023. In addition, the Province of Alberta has established a reduction goal of 45% for methane gas emissions by 2025. To achieve that goal, in December 2018 the Alberta Energy Regulator issued prescriptive measures to reduce methane by implementing emissions design standards on new facilities, addressing venting from existing equipment, and increasing measurement, reporting and fugitive emissions requirements. These requirements intend to achieve equivalency with the federal methane emissions reduction regulations issued in April 2018. The Corporation estimates it could incur an additional $300,000 per year in costs due to equipment retrofits, increased measurement and reporting work, and higher frequency of fugitive leak inspections. Alberta also has emission reduction targets for large emitters (e.g., 100,000 tonnes of CO 2 e per year at a single facility). Currently, the Corporation does not operate any facility classed within this large emitter category.

 

In May of 2010 the Province of Saskatchewan’s The Management and Reduction of Greenhouse Gases Act (“ GHG Act ”) received royal assent with only certain portions proclaimed in force on January 1, 2018. The Province of Saskatchewan has established a goal of reducing GHG emissions from the province’s upstream oil and gas sector by 40% to 45% from 2015 levels by 2025. In December of 2017, the Government of Saskatchewan released a climate change strategy entitled  Prairie Resilience: A Made in Saskatchewan Climate Change Strategy  (the “ Strategy” ) to affirm provincial regulatory jurisdiction over emissions regulation. This Strategy focuses on sector-specific approaches and climate change adaptation. The Government of Saskatchewan has publicly stated that the Saskatchewan regulatory package provides an alternative, robust plan to the federal GHG emission reduction regulations to help Saskatchewan achieve climate change goals, while also providing industry with the flexibility to implement measures in an effective, economically viable way.  Pursuant to the Strategy, the Province of Saskatchewan released The Oil and Gas Emissions Management Regulations  (the “ OGEMR ”), which came into effect January 1, 2019 and are applicable to entities whose combined potential emissions are greater than 50,000 tonnes of CO 2 e per year. Currently, the Corporation’s annual emissions in Saskatchewan are well beneath this threshold.  The Province of Saskatchewan is currently challenging in court the federal government’s plan to impose a carbon tax. Saskatchewan believes its climate change plan, which does not include a carbon tax, is enough to reduce emissions. Until a decision has been made by the Saskatchewan Court of Appeal, the Corporation will assess the carbon tax impacts on its Saskatchewan operations based on rates outlined in the federal GHGPPA. 

 

The Corporation believes that it is, and expects to continue to be, in material compliance with applicable environmental laws and regulations and is committed to meeting its responsibilities to protect the environment wherever it operates or holds working interests. The Corporation anticipates that this compliance may result in increased costs of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment. The Corporation believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. See " Risk Factors – The Corporation's operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities, including those related to climate change,   as well as public opposition and activism ” and " Risk Factors – Government policy and/or regulations and required regulatory   approvals and compliance may adversely impact the Corporation's operations and result in increased operating and capital costs ".

 

WORKER SAFETY

 

The Corporation’s oilfield operations must be carried out in accordance with safe work procedures, rules and policies contained in applicable safety legislation. Such legislation requires that every employer ensures the health and safety of all persons at any of its work sites and all workers engaged in the work of that employer. The legislation, which provides for incident reporting procedures, also requires every employer to ensure all of its employees are aware of their duties and

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responsibilities under the applicable legislation. Penalties under applicable occupational health and safety legislation include significant fines and incarceration. The Corporation is currently in compliance with applicable safety legislation.

 

 

Risk Factors

 

The following risk factors, together with other information contained in this Annual Information Form and other filings, including the Corporation’s MD&A,  and its Financial Statements and related notes, should be carefully considered before investing in the Corporation. Each of these risks may negatively affect the trading price of the Common Shares or the amount of dividends that may, from time to time and at the discretion of the Corporation's board of directors, be declared and paid by the Corporation to its shareholders.

 

Please note, all references to “natural gas” in this section refer to both natural gas and shale gas.

 

Oil and natural gas prices are volatile. An extended period of low oil and natural gas prices could have a material adverse effect on the Corporation's business, results of operations, or cash flows and financial condition.

 

The Corporation's results of operations and financial condition are dependent on the prices it receives for the oil and natural gas it produces and sells. Oil and natural gas prices have fluctuated widely during recent years and may continue to be volatile in the future. These price fluctuations have been in response to a variety of factors beyond the Corporation's control, including: 

·

global energy supply and demand, production and policies, including the ability of OPEC or non-OPEC members to set, maintain, or reduce production levels to help in achieving a balanced market

·

political conditions, including the risk of hostilities in the Middle East and global terrorism

·

global and domestic economic conditions and currency fluctuations

·

the level of consumer demand, including demand for different qualities and types of crude oil, NGLs and natural gas

·

the production and storage levels of North American natural gas and crude oil, and the supply and price of imported oil and liquefied natural gas

·

weather conditions

·

the proximity of reserves   and resources to, and capacity of, transportation facilities, and the availability of refining, processing and fractionation capacity

·

the ability, considering regulation, taxation, and market demand, to export crude oil and liquefied natural gas and NGLs from North America

·

the effect of world‑wide energy conservation and greenhouse gas reduction measures and the price and availability of alternative fuels

·

existing and proposed changes to government regulations and policy decisions

 

Oil and natural gas producers in North America may receive significantly discounted prices for some of their production due to regional constraints on the ability to transport and sell such production to international markets. Additionally, limited natural gas and NGLs processing capacity or other infrastructure constraints may result in producers not realizing the full price for their production. The inability to resolve such constraints may result in continued reduced commodity prices received by oil and natural gas producers such as the Corporation.

 

Future declines in crude oil and/or natural gas prices, or an extended low commodity price environment, may have a material adverse effect on the Corporation's operations and cash flows, financial condition, borrowing ability, levels of reserves and resources, and the level of expenditures for the development of the Corporation's oil and natural gas reserves or resources. Certain oil or natural gas wells may become or remain uneconomic to proceed with as part of the Corporation’s exploration or development plans or projects if commodity prices are low, thereby impacting the Corporation's production volumes. Low prices may also impact the Corporation’s desire to market its production under unsatisfactory market conditions. Alternatively, due to regulatory or contractual obligations, the Corporation may be required to produce from or develop certain properties to fulfill its obligations despite unsatisfactory market conditions for marketing of any production therefrom, increasing the risk of financial losses. Furthermore, the Corporation may be subject to the decisions of third party operators who, independently and using different economic parameters than the Corporation, may decide to curtail or shut-in jointly owned production.

 

Government policy and/or regulations and required regulatory approvals and compliance may adversely impact the Corporation's operations and result in increased operating and capital costs.

 

The oil and gas industry operates under federal, provincial, state and municipal legislation and regulation governing such matters as royalties, land tenure, prices, production rates, various environmental protection controls, well and facility design and operation, income, the exportation of crude oil, natural gas and other products, as well as other matters. The industry is also subject to regulation by governments in such matters as the awarding or acquisition of exploration and production

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rights, the imposition of specific drilling obligations, the imposition of production curtailments, control over the development and abandonment of fields (including restrictions on production), restrictions on the combustion of natural gas and possibly expropriation or cancellation of contract rights. See " Industry Conditions ". To the extent the Corporation fails to comply with applicable government regulations or regulatory approvals, the Corporation may be subject to compliance and enforcement actions that are either remedial, which are intended to fix the noncompliance and any related impacts, or punitive, which are intended to deter future noncompliance. Such actions include fines or fees, notices of non-compliance, warnings, orders, administrative sanctions, and prosecution. In addition, obstructive tactics which could prevent certain measures from being voted upon in the United States legislature, or any government action resulting in a prolonged government shutdown, may impact the Corporation as a result of its inability to obtain regulatory and other approvals.

 

Government regulations may be changed from time to time in response to economic or political conditions. Additionally, the Corporation's entry into new jurisdictions and its adoption of new technology may attract additional regulatory oversight which could result in higher costs or require changes to proposed operations. U.S. federal and state and Canadian federal and provincial governments continue to scrutinize the usage and disposal of chemicals and water used in fracturing procedures in the oil and gas industry, while certain states have called for bans on oil and gas drilling using hydraulic fracturing. More activity by the Corporation on Indian lands in the United States, or lands held by Indigenous groups in Canada, may also increase compliance obligations under tribal or local rules. The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations, or the modification of existing regulations affecting the crude oil and natural gas industry could negatively impact the development of oil and gas properties and assets, reduce demand for, or restrict the supply of, crude oil and natural gas production, or impose increased costs on oil and gas companies, any of which could have a material adverse impact on the Corporation.

 

Additionally, various levels of Canadian and U.S. governments are considering, or have implemented, legislation to reduce emissions of greenhouse gases, including volatile organic compounds. See " Industry Conditions – Environmental Regulation " for a description of these initiatives. Because the Corporation's operations emit various types of GHGs, such new legislation or regulations could increase the costs related to operating and maintaining the Corporation's facilities, and could require it to install new emission controls on its facilities, acquire allowances for its GHG emissions, shut-in production, pay taxes, fees and other penalties related to its GHG emissions, and administer and manage a GHG emissions program. Currently, the Corporation is not able to estimate such increased costs; however, they could be material. Any of the foregoing could have adverse effects on the Corporation's business, financial position, results of operations and prospects.

 

The Corporation's operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities, including those related to climate change, as well as public opposition and activism.

 

GENERAL

 

The oil and natural gas industry elicits concerns about climate change, as well as general public opposition to the industry. As a result, industry participants may be subject to increased public activism, as well as extensive environmental regulation pursuant to local, provincial, and federal legislation in Canada and federal and state laws and regulations in the United States. Activist activity may result in increased costs due to delays or damage, while defaults by the Corporation under applicable legislation could result in the imposition of fines or the issuance of "clean up" orders. Legislation regulating the industry may be changed to impose higher standards and potentially more costly obligations, such as legislation requiring significant reductions in GHG emissions or setback requirements for facilities and wells. Failure to comply with such regulations and laws can result in significant increases in costs, penalties, or loss of operating licenses. The actual form of such legislation or regulation is evolving. Further, the business of exploration, development and production of oil and natural gas wells and facilities is subject to the risks and hazards associated with such operations. These include, but are not limited to, blowouts, fire, explosion, environmental releases (including sour gas), induced seismicity, and other safety hazards, which could result in significant damage to the Corporation’s property, personal injury, loss of life, and liability to regulators or third parties.  

 

The Corporation is not fully insured against all environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damage) is not available on economically reasonable terms. Accordingly, the Corporation's properties may be subject to liability due to hazards that cannot be insured against or that have not been insured against due to prohibitive premium costs or for other reasons.

 

The Corporation does not establish a separate reclamation fund for the purpose of funding its estimated future environmental and reclamation obligations. The Corporation cannot assure investors that it will be able to satisfy its future environmental and reclamation obligations. Any site reclamation or abandonment costs incurred in the ordinary course, in a specific period, will be funded out of cash flows and, therefore, will reduce the amounts that may be available for development of projects and resources, debt repayments, or as available cash for dividends to shareholders. Further, the availability in some jurisdictions of monies collected via levies on oil and gas producers, in order to cover remediation and/or reclamation costs incurred by the Corporation on behalf of insolvent or defunct partners, may be reduced or eliminated as such funds become depleted. Should the Corporation be unable to fully fund the cost of remedying an environmental claim,

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the Corporation might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

 

RISKS RELATING TO FRACTURING

 

The Corporation utilizes horizontal drilling, multi‑stage hydraulic fracturing, specially formulated drilling fluids, and other technologies in connection with its drilling and completion activities. There has been public concern over the hydraulic fracturing process. Most of these concerns have raised questions regarding the drilling fluids and the volume of fluid used in the fracturing process, their effect on fresh water aquifers, the use of water in connection with completion operations, the ability of such water to be recycled, and induced seismicity associated with fracturing. The U.S. and Canadian governments, including certain U.S. state and Canadian provincial governments, may review aspects of the scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. At present, most of these governments are primarily engaged in the collection, review and assessment of technical information regarding the hydraulic fracturing process and, with the exception of increased chemical disclosure requirements in certain of the jurisdictions in which the Corporation operates, have not provided specific details with respect to any significant actual, proposed or contemplated changes to the hydraulic fracturing regulatory construct. However, certain environmental and other groups have suggested that additional federal, provincial, territorial, state and municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Claims have been made that hydraulic fracturing techniques are harmful to surface water and drinking water sources and may contribute to earthquake activity, particularly where operators are in proximity to pre‑existing faults. Governmental authorities in jurisdictions where the Corporation does not currently operate have either implemented or considered temporary moratoriums on hydraulic fracturing until further studies can be completed, and some governments have adopted or considered adopting regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations.

 

It is anticipated that federal, provincial and state regulatory frameworks to address concerns related to hydraulic fracturing will continue to emerge. While the Corporation is unable to predict the impact of any potential regulations upon its business, the implementation of new laws, regulations or permitting requirements with respect to water usage or disposal, or hydraulic fracturing generally, could increase the Corporation's costs of compliance, operating costs, the risk of litigation and environmental liability, or negatively impact the Corporation's production and prospects, any of which may have a material adverse effect on the Corporation's business, financial condition and results of operations.

 

RISKS RELATING TO CLIMATE CHANGE

 

Public support for climate change action and receptivity to new technologies has grown in recent years. Governments in Canada and around the world have responded to these shifting societal attitudes by adopting ambitious emissions reduction targets and supporting legislation, including measures relating to carbon pricing, clean energy and fuel standards, and alternative energy incentives and mandates. There has also been increased activism,  including threats of culpability, legal action against oil and gas producers, and public opposition to fossil fuels and the oil and gas industry in which the Corporation operates. See “ Industry Conditions – Environmental Regulation ”. Public and government hostility toward the oil and gas industry could reduce demand for oil and gas and, therefore, adversely affect market prices for the Corporation’s production. Existing and future laws and regulations may impose additional costs on companies operating in the oil and gas industry or significant liabilities for failure to comply with their requirements. Concerns over climate change and fossil fuel extraction could lead governments to enact additional or more stringent laws and regulations applicable to the Corporation and other companies in the energy industry in general.

 

Lack of adequately developed infrastructure, and the impact of special interest groups on such development, may result in a decline in the Corporation's ability to market its oil and natural gas production.

 

The Corporation's business depends in part upon the availability, proximity, and capacity of oil and natural gas gathering systems, pipelines and/or rail transportation systems and processing facilities to provide access to markets for its production. U.S. federal and state, as well as Canadian federal and provincial, regulation of oil and natural gas production and processing and transportation could adversely affect the Corporation's ability to produce and market oil, natural gas and NGLs. Special interest groups could also oppose infrastructure development, resulting in delays or even cancellation of construction of the required infrastructure, further impeding the Corporation’s ability to produce and market its products. In addition, the assets of the Corporation are concentrated in regions with varying levels of government regulations, or under tribal or local rules that could result in the imposition of a limit or ban on shipping of commodities by truck, pipeline or rail.

 

OIL AND NATURAL GAS GATHERING SYSTEMS

 

Development of new resource plays generally results in a sharp increase in the volume of oil and natural gas being produced in the area, which could exceed government-regulated gas capture requirements, or the existing capacity of the various gathering system infrastructure. The Corporation relies on the timely construction of adequate gathering systems that allow

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its crude oil and natural gas production to be transported from the wellhead to existing and/or new sales infrastructure systems, such as pipelines or rail terminals.

 

The pace at which producer or midstream companies can construct adequate gathering infrastructure to capture the natural gas associated with the development of crude oil and NGLs properties may have an impact on the Corporation’s ability to increase crude oil production in its producing regions. Additionally, as exploration and drilling in these regions increases, the amount of natural gas being produced by the Corporation and others could exceed the capacity of the various gathering pipelines available in those areas. If these constraints remain unresolved, the Corporation's ability to transport its production to sales pipelines in these regions may be impaired and could adversely impact the Corporation's production volumes or realized prices in these areas.

 

SALES PIPELINES AND RAIL TRANSPORTATION SYSTEMS

 

Oil and natural gas producers in certain regions of North America may receive significantly discounted prices relative to benchmark prices for their production due to constraints on the ability to transport and sell such production to domestic and international markets. While third party pipeline and railroad companies generally expand capacity to meet market needs, there can be differences in timing between the growth of production and the growth of sales pipeline and rail capacity. This is currently the case with natural gas and crude oil sales pipelines in Alberta and British Columbia, as there is generally inadequate sales pipeline capacity to transport production out of these regions, resulting in volume curtailments and low regional commodity prices. To a lesser extent this risk exists with natural gas and crude oil sales pipeline capacity in North Dakota. Unfavourable economic conditions or financing terms, as well as significant delays in the regulatory approval process, may defer or prevent the completion of certain pipeline projects, gathering systems or railway projects that are planned for such areas. There may also be operational or economic reasons, including but not limited to maintenance activities, for curtailing transportation capacity. In addition, there could be legal or regulatory challenges by third parties on existing sales pipelines, which could impact a pipeline’s ability to provide services to shippers. Accordingly, there can be periods where transportation capacity is insufficient to accommodate all the production from a given region, causing added expense and/or volume curtailments for all shippers. To the extent that the transportation capacity becomes insufficient in areas where the Corporation operates, the Corporation may have to defer the development of, curtail production from or shut-in wells awaiting a pipeline connection or other available transportation capacity, and/or sell its production at lower prices than it would otherwise realize or it had projected to realize. This would adversely affect the Corporation's results of, and cash flow from, operations.

 

The Corporation transports its crude oil production by a diverse mix of pipeline, trucking and, on occasion, rail (after title is transferred to the buyer’s name), all of which are subject to various risks of cost escalation and/or new costs. In certain regions the Corporation is currently dependent upon only one means of transportation. With respect to rail transportation, there may be future incremental costs associated with transporting, and there is a risk that access to rail transport may be constrained, depending upon changes made to existing rail transport regulations. More stringent government regulations concerning the usage of certain types of tank cars that transport crude oil and NGLs by rail in the United States and Canada have been enacted, and this could increase the cost of utilizing rail to transport crude oil and/or NGLs. In addition, oil and natural gas volumes being shipped by pipelines are required to meet certain quality specifications, which vary by pipeline. Should crude oil, natural gas or NGLs quality specifications fail to be met by a producer that is shipping volumes on a pipeline, the pipeline could shut down or curtail volumes of other producers shipping on that pipeline. Any shutdown, curtailment, reversal of pipeline flow, or a change in the commodity being transported on pipelines shipping volumes of the Corporation’s production may impact the Corporation’s ability to reach its intended market, or deliver fully on its obligations.

 

ACCESS TO PROCESSING FACILITIES

 

NGLs production requires processing at fractionation facilities to separate the liquids stream into individual saleable products. The Corporation and the industry rely on the addition of adequate fractionation capacity to ensure the timely and economic processing of NGLs and the continued production of crude oil and natural gas associated with those liquids. Limited natural gas processing capacity in certain regions may result in producers not realizing the full price for NGLs associated with their natural gas production.

 

Crude oil and natural gas production requires processing at certain facilities in order to be transported on regional pipeline systems. The Corporation and the industry rely on the addition of adequate natural gas and other processing capacity to ensure the timely and economic processing of natural gas production, and the continued production of crude oil and NGLs, as well as any associated natural gas production. Limited natural gas processing capacity in certain regions may result in producers not being able to sell some or all of their natural gas production,  lead to curtailment of crude oil production, or result in not realizing the full value of their natural gas production.

 

A failure to resolve any of the constraints described above may result in the Corporation failing to comply with certain environmental regulations, shutting‑in production, or receiving continued reduced commodity prices. 

 

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An increase in capital or operating costs could have a material adverse effect on results of operations or cash flows and financial condition.

 

Higher capital or operating costs associated with the Corporation's operations will directly impact its capital efficiencies and/or decrease the amount of the Corporation's cash flow. Capital costs of completions, specifically the costs of proppant, pumper services, and operating costs such as electricity, chemicals, supplies, energy services and labour costs, are a few of the Corporation's costs that are susceptible to material fluctuation. Although the Corporation has a portion of its current capital and operating costs   protected with existing agreements, changing regulatory conditions, such as those in the U.S. requiring certain raw materials, such as steel, for use in U.S. businesses to be sourced from the U.S., or that goods and/or services be procured from specific vendors or classes of vendors, may result in higher than expected supply costs for the Corporation.

 

Higher than expected declines or curtailments in the Corporation’s production due to infrastructure constraints,   third party operational business practices or failures, or government regulation could have an adverse effect on results of operations or cash flows and financial condition.

 

Continued industry production growth for any of the Corporation’s products may exceed the capacity of existing pipeline infrastructure until debottlenecking is undertaken or completed. During such periods, regional prices may decline to levels where the Corporation considers, or governments mandate, curtailment of production. In some cases, alternate shipping methods, such as rail for crude oil, may be used and could result in higher costs and lower netbacks. In addition, the continuing production from a property, and to some extent the marketing of that production, is dependent upon the abilities of the operators of the Corporation's properties. A significant portion of the Corporation's production is from properties operated by third parties. This results in significant reliance on third party operators in both the operation, including the decision to curtail production due to low prices, and the development of such properties.

 

Operating agreements governing properties not operated by the Corporation typically require the operator to conduct operations in a “good and workmanlike" manner. These operating agreements generally exempt the operator from liability to the other non‑operating working interest owners for losses sustained or liabilities incurred, except for liabilities that may result from the operator’s gross negligence or wilful misconduct. To the extent a third-party operator fails to perform its duties properly, faces capital or liquidity constraints or becomes insolvent, the Corporation's results of operations may be negatively impacted.

 

The timing and amount of capital required to be spent by the Corporation may also differ from the Corporation's expectations and planning, and may impact the ability of and/or cost to the Corporation to finance such expenditures, as well as adversely affect other parts of the Corporation's business and operations.

 

As a result of the foregoing, the Corporation may be required to curtail or shut-in production, which could damage a reservoir and potentially prevent the Corporation from achieving production and operating levels that were in place prior to the curtailment or shutting-in of the reservoir. In addition, the lower levels of production could result in a material reduction to the Corporation’s cash flow, or may result in the Corporation incurring additional operating and capital costs for the well(s) to achieve prior production levels.

 

If the Corporation expands beyond its current areas of operations or expands the scope of operations beyond oil and natural gas production, the Corporation may face new challenges and risks. If the Corporation is unsuccessful in managing these challenges and risks, its results of operations and financial condition could be adversely affected.

 

The Corporation may acquire oil and natural gas properties and assets outside the geographic areas in which it has historically conducted its business and operations. The expansion of the Corporation's activities into new locations may present challenges and risks that the Corporation has not faced in the past, including operational and additional regulatory matters. In addition, the Corporation's activities are not limited to oil and natural gas production and development, and the Corporation could acquire other energy related assets. Expansion of the Corporation's activities into new business areas may present challenges and risks that it has not faced in the past, including dealing with additional regulatory matters. If the Corporation does not manage these challenges and risks successfully, its results of operations and financial condition could be adversely affected.

 

The Corporation's expanded scope of activities and participation in the capital markets may attract increased criticism, shareholder activism and costly litigation.

 

The expansion of the Corporation's business activities, both geographically and with a focus on exploration and development of unconventional reservoirs, may draw increased attention from shareholder activists who oppose the strategy of the Corporation, including its operation of the business, its plans for development and its capital allocation decisions, which could have an adverse effect on market value. The Corporation’s ongoing participation in the Canadian and U.S. capital markets may expose the Corporation to greater risk of class action lawsuits related to, among other things,

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securities law matters (including with regard to alleged deficiencies in the Corporation’s public disclosure), title, contractual and environmental matters.

 

Changes in laws or free trade agreements, including those affecting tax, royalties and other financial and trade matters, and interpretations of those laws and trade agreements, may adversely affect the Corporation and its securityholders.

 

Tax laws, including those that may affect the taxation of the Corporation, or other laws or government incentive programs relating to the oil and gas industry generally, may be changed, or interpreted in a manner that adversely affects the Corporation and its securityholders. Canadian, U.S. and foreign tax authorities having jurisdiction over the Corporation (whether as a result of the Corporation's operations or its financing structures), may change or interpret applicable tax laws, treaties or administrative positions in a manner which is detrimental to the Corporation or its securityholders. Tax authorities may disagree with how the Corporation calculates its income for tax purposes. The Corporation may be subject to additional taxation (direct or indirect, including carbon tax, goods and services tax, or sales tax), levies or royalty payments imposed by government and tribal authorities with jurisdiction over its properties. The Corporation has income and other tax filings that are subject to audit and potential reassessment which may impact the Corporation's tax liability. The Corporation believes appropriate provisions for current and deferred income taxes have been made in its Financial Statements; however, it is difficult to predict the outcome of audit findings by tax authorities. These findings may increase the amount of its tax liabilities and be detrimental to the Corporation. In addition, the U.S., Mexico and Canada negotiated certain changes to NAFTA, as proposed in the USMCA (U.S.-Mexico-Canada Agreement), which may lead to the imposition of additional duties and tariffs, and could result in other changes that could negatively impact the Corporation’s business.

 

Changes in market‑based factors and investor strategies may adversely affect the trading price of the Common Shares and/or the Corporation’s stock exchange listings.

 

The market price of the Common Shares is primarily a function of the value of the properties owned by the Corporation, as well as the anticipated growth in production and cash flow, and dividends paid to shareholders. The market price of the Common Shares is also sensitive to a variety of market‑based factors, including, but not limited to, an increase in passive investing (through vehicles such as exchange traded funds) and options trading, the inclusion or removal of the Common Shares from one or more stock market indexes or exchange traded funds, interest rates, and the comparability of the Corporation’s performance to other growth or yield‑oriented exploration and production companies. Additionally, the Common Shares may, from time to time, not meet the investment criteria or characteristics of a particular institutional or other investor, including for reasons unrelated to financial or operational performance. Any changes in market‑based factors or investor strategies, including responsible investing criteria/rankings (for example, social impact or environmental scores), the implementation of new financial market regulations such as the Markets in Financial Instruments Directive (MiFID II) and fossil fuel divestment initiatives undertaken by governments, pension funds and/or other institutional investors, may adversely affect the trading price of the Common Shares, and/or their inclusion in the portfolios of investment managers. In addition, should the trading price of the Common Shares fall below stock exchange listing thresholds, the exchanges will review the appropriateness of the Common Shares for continued listing (NYSE) or ongoing listing (TSX).

 

The Corporation's expanding portfolio of growth‑oriented projects may expose it to increased operational and financial risks.

 

The Corporation's unconventional oil and gas operations (such as the development of and production from shale formations) involve certain additional risks and uncertainties. The drilling and completion of wells and operations on these unconventional assets present certain challenges that differ from conventional oil and gas operations. Wells on these properties generally must be drilled deeper than in many other areas, which makes the wells more expensive to drill and complete. To reduce costs, wells may be drilled as part of a multi-well pad which may increase the risk of being unable to drill and complete any of the wells on the pad if problems occur. In addition, because of the depth and length of these unconventional wells, they also may be more susceptible to mechanical problems associated with drilling and completion, such as casing collapse and lost equipment in the wellbore. In addition, the fracturing activities required to be undertaken on these unconventional assets may be more extensive and complicated than fracturing the geological formations in the Corporation's other areas of operation and require greater volumes of water than conventional wells. The management of water and the treatment of produced water from these wells may be more costly than the management of produced water from other geologic formations. In addition, to the extent the Corporation acquires properties or assets with a higher exploration risk profile, the risk associated with such acquisitions and the future development of those assets is more uncertain.

 

The Corporation may be unable to add or develop additional reserves or resources.

 

The Corporation adds to its oil and natural gas reserves primarily through acquisitions and ongoing development of its existing reserves and resources, together with certain exploration activities. As a result, the level of the Corporation's future oil and natural gas reserves is highly dependent on its success in developing and exploiting its reserves and resources base and acquiring additional reserves and/or resources through purchases or exploration. Exploitation, exploration and

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development risks arise for the Corporation and, as a result, may affect the value of the Common Shares and dividends to shareholders due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. Additionally, if capital from external sources is not available or is not available on commercially advantageous terms, the Corporation's ability to make the necessary capital investments to maintain, develop or expand its oil and natural gas reserves and resources will be impaired. Even if the necessary capital is available, the Corporation cannot assure that it will be successful in acquiring additional reserves or resources on terms that meet its investment objectives. Without these additions, the Corporation's reserves will deplete and, as a consequence, either its production or the average life of its reserves will decline.

 

The Corporation's actual reserves and resources will vary from its reserves and resources estimates, and those variations could be material.

 

The value of the Common Shares depends upon, among other things, the reserves and resources attributable to the Corporation's properties. The actual reserves and resources contained in the Corporation's properties will vary from the estimates summarized in this Annual Information Form and those variations could be material. Estimates of reserves and resources are by necessity projections, and thus are inherently uncertain. The process of estimating reserves or resources requires interpretations and judgments on the part of petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Different engineers may make different estimates of reserves or resources quantities and revenues attributable thereto based on the same data. The reserves and resources information contained in this Annual Information Form is only an estimate. A number of factors are considered and a number of assumptions are made when estimating reserves and resources, such as, among others described in this Annual Information Form:

·

historical production in the area compared with production rates from similar producing areas

·

future commodity prices, production and development costs, royalties and planned capital expenditures

·

initial production rates and production decline rates

·

ultimate recovery of reserves and resources and the success of future exploitation activities

·

marketability of production

·

the effects of government regulation and other government royalties or levies, such as environmental costs, that may be imposed over the producing life of reserves and resources

 

Reserves and resources estimates are based on the relevant factors, assumptions and prices on the date the evaluations were prepared. Many of these factors are subject to change and are beyond the Corporation's control. If these factors, assumptions and prices prove to be inaccurate, the Corporation's actual reserves and resources could vary materially from its estimates. Additionally, all such estimates are, to some degree, uncertain, and classifications of reserves and resources are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable quantities of oil and natural gas, the classification of such reserves and resources based on risk of recovery and associated contingencies, and the estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially.

 

Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric or probabilistic calculations and upon analogy to similar types of reserves or resources, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves or resources based upon production history may result in variations or revisions in the estimated reserves or resources, and any such variations or revisions could be material.

 

Reserves and resources estimates may require revision based on actual production experience. Such figures have been determined based upon assumed oil, natural gas and NGLs prices and operating costs. Market price fluctuations of commodity prices may render uneconomic the recovery of certain categories of petroleum or natural gas. Moreover, short‑term factors may impair the economic viability of certain reserves or resources in any particular period. With commodity prices remaining volatile, there is a risk for write-downs under U.S. GAAP. See “ Risk Factors – Lower oil and gas prices and higher costs increase the risk of write-downs of the Corporation’s oil and gas properties and deferred tax assets” . Write-downs may lead to the Corporation breaching its covenants under the Bank Credit Facility, and the Corporation may not be able to negotiate any covenant relief. See " Risk Factors – Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief.”

 

The Corporation may be unable to compete successfully with other organizations in the oil and natural gas industry, or obtain required vendor services to compete. 

 

The oil and natural gas industry is highly competitive. The Corporation competes for capital, acquisitions of reserves   and/or resources, undeveloped lands, skilled/qualified labour, access to drilling rigs, service rigs and other equipment and materials such as sand and other proppant, hydraulic fracturing pumping equipment and related skilled personnel, access to processing facilities, pipeline and refining capacity, as well as many other services, and in many other respects, with a substantial number of other organizations, many of which may have greater technical and financial resources than the Corporation. Some of these organizations not only explore for, develop and produce oil and natural gas, but also conduct

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refining operations and market oil and other products on a world‑wide basis. As a result of these complementary activities, some of the Corporation's competitors may have greater opportunities and more diverse resources to draw upon. Also, organizations that have complementary activities or are integrated may have access to, or be able to access, services or vendors that the Corporation is not able to access, thereby limiting its ability to compete.  

 

Service providers are also in a highly competitive environment. Should low commodity prices prevail, some may choose or be required to streamline or discontinue their business, further reducing the supply of vendors and potentially increasing the competition for service, and thereby the costs to producers.

 

In addition, the Corporation may be at a competitive disadvantage to other industry participants able to minimize taxes under more favourable tax jurisdictions and/or regulatory environments, or which have access to a lower cost of capital.

 

Delays in payment for business operations, including the risk of default by counterparties to contracts, could adversely affect the Corporation.

 

In addition to the potential delays in payment by purchasers of oil and natural gas to the Corporation or to the operators of the Corporation's properties (and the delays of those operators in remitting payment to the Corporation), payments between any of these parties or any counterparties to contracts (including the Corporation’s risk management, marketing, purchase and sale agreements, supplier and service contract counterparties) may also be delayed, or result in default due to, among other things: 

·

substantial or extended declines in oil, NGLs and natural gas prices

·

capital or liquidity constraints experienced by such parties, including restrictions imposed by lenders

·

accounting delays or adjustments for prior periods

·

shortages of, or delays in, obtaining qualified personnel or equipment, including drilling rigs and completions services

·

delays in the sale or delivery of products, or delays in the connection of wells to a gathering system

·

adverse weather conditions, such as freezing temperatures, storms, flooding and premature thawing

·

blow‑outs or other accidents

·

title defects

·

recovery by the operator of expenses incurred in the operation of the properties, or the establishment by the operator of reserve funds for these expenses

 

Any of these delays could reduce the amount of the Corporation's cash flow and the payment of cash dividends to its shareholders in a given period. Any of these delays could also expose the Corporation to additional third-party credit risks.

 

The Corporation's information assets and critical infrastructure may be subject to cyber security risks.

 

The Corporation is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Corporation's information technology systems by third parties or insiders. Although the Corporation has security measures and controls in place that are designed to mitigate these risks, a  breach of its security measures and/or a loss of information could occur and result in a loss of material and confidential information and reputation, breach of privacy laws, and/or disruption to business activities. 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 the Corporation's business, financial condition and results of operations.

 

The Corporation may lose its current status as a "foreign private issuer" in the United States, which may result in additional compliance costs and restricted access to capital markets.

 

The Corporation is required to assess its "foreign private issuer" status under U.S. securities laws on an annual basis at the end of its second quarter. If the Corporation were to lose its status as a "foreign private issuer" under U.S. securities laws and be required to fully comply with both U.S. and Canadian securities and accounting requirements applicable to domestic issuers in each country, it could incur additional general and administrative compliance costs and have restricted access to capital markets for a period of time until it has the required approvals in place from the SEC.

 

Lower oil and gas prices and higher costs increase the risk of write‑downs of the Corporation's oil and gas properties and deferred tax assets.

 

Under U.S. GAAP, the net capitalized cost of oil and gas properties, net of deferred income taxes, is limited to the present value of after‑tax future net revenue from proved reserves, discounted at 10%, and based on the unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the issuer's fiscal quarter and annual fiscal periods. The amount by which the net capitalized costs exceed the discounted value will be charged to net income. The Corporation incurred no non-cash asset impairments in 2018.

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Under U.S. GAAP, the net deferred tax assets of a corporation are limited to the estimate of future taxable income resulting from existing properties. The Corporation estimates future taxable income based on before‑tax future net revenue from proved plus probable reserves, undiscounted, using forecast prices, and adjusted for other significant items affecting taxable income. The amount by which the gross deferred tax assets exceed the estimate of future taxable income will be charged to net income. A previously recorded valuation allowance can be reversed if the estimate of future taxable income increases.

 

If commodity prices were to decline, there remains a risk for additional write-downs under U.S. GAAP. While these write‑downs would not affect cash flow, the charge to earnings may be viewed unfavourably in the market. Additional write-downs may lead to the Corporation breaching its covenants under the Credit Facilities, and the Corporation may not be able to negotiate any covenant relief. See " Risk Factors – Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief.”

 

The Corporation may require additional financing to maintain and/or expand its assets and operations.

 

In the normal course of making capital investments to maintain and/or expand the Corporation's oil, NGLs and natural gas reserves and resources, additional Common Shares or other securities of the Corporation may be issued, which may result in a decline in production per share and reserves and/or resources per share. Additionally, from time to time the Corporation may issue Common Shares or other securities from treasury in order to reduce debt, complete acquisitions, and maintain a more optimal capital structure. The Corporation may also divest of existing properties or assets as a means of financing alternative projects or developments. To the extent that external sources of capital, including the availability of debt financing from banks or other creditors or the issuance of additional Common Shares or other securities, become limited, unavailable or available on less favourable terms, the Corporation's ability to make the necessary capital investments to: (i) retain leases, (ii) carry out its operations, and/or (iii) maintain and/or expand its oil, NGLs and natural gas reserves and resources could be adversely affected. To the extent that the Corporation is required to use additional cash flow to finance capital expenditures or property acquisitions, or to pay debt service charges or to reduce debt, the level of cash that may be available for the Corporation to pay dividends to its shareholders may be reduced.

 

The Corporation may not realize the anticipated benefits of its acquisitions or divestments.

 

From time to time, the Corporation may acquire additional oil and natural gas properties and related assets. Achieving the anticipated benefits of such acquisitions will depend in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the Corporation's ability to realize the anticipated growth opportunities and synergies from combining and integrating the acquired assets and properties into the Corporation's existing business. These activities will require the dedication of substantial management effort, time and capital and other resources, which may divert management's focus, capital and other resources from other strategic opportunities and operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the Corporation's ability to achieve the anticipated benefits of current or future acquisitions. The risk factors set forth in this Annual Information Form relating to the oil and natural gas business and the operations, reserves and resources of the Corporation apply equally in respect of any future properties or assets that the Corporation may acquire. The Corporation generally conducts certain due diligence in connection with acquisitions, but there can be no assurance that the Corporation will identify all of the potential risks and liabilities related to the subject properties.

 

When acquiring assets, the Corporation is subject to inherent risks associated with predicting the future performance of those assets. The Corporation makes certain estimates and assumptions respecting the prospectivity and characteristics of the assets it acquires, which may not be realized over time. As such, assets acquired may not possess the value the Corporation attributed to them, which could adversely impact the Corporation's cash flows. To the extent that the Corporation makes acquisitions with higher growth potential, the higher risks often associated with such potential may result in increased chances that actual results may vary from the Corporation's initial estimates. An initial assessment of an acquisition may be based on a report by engineers or firms of engineers that have different evaluation methods, approaches and assumptions than those of the Corporation's engineers, and these initial assessments may differ significantly from the Corporation's subsequent assessments.

 

Furthermore, potential investors should be aware that certain acquisitions, and in particular those that are higher risk/higher growth assets and the development of those acquired assets, may require more capital than anticipated from the Corporation, and the Corporation may not receive cash flow from operations from these acquisitions for several years, or may receive cash flow in an amount less than anticipated.

 

The Corporation may also from time to time seek to divest of properties and assets. These divestments may consist of non‑core properties or assets, or may consist of assets or properties that are being monetized to fund debt repayment, alternative projects, or development by the Corporation. There can be no assurance that the Corporation will be successful in such divestments, or realize the amount of desired proceeds from such divestments, or that such divestments will be viewed positively by the financial markets, and such divestments may negatively affect the Corporation's results of

50      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

operations or the trading price of the Common Shares. In addition, although divestments typically transfer future obligations to the buyer, the Corporation may not be exempt from certain obligations in the future, including for example, abandonment and reclamation obligations, which may have an adverse effect on the Corporation’s operations and financial condition.

 

The Corporation's risk management activities, as well as ongoing regulatory changes affecting financial institutions, could expose it to losses.

 

The Corporation may use financial derivative instruments and other hedging mechanisms to limit a portion of the adverse effects resulting from volatility in natural gas and oil commodity prices. To the extent the Corporation hedges its commodity price, interest rate and foreign exchange exposure, it may forego the benefits it would otherwise experience. In addition, the Corporation's commodity price, interest rate and foreign exchange hedging activities, as well as changing bank regulations that may limit liquidity in the commodity markets, could expose it to losses. These losses could occur under various circumstances, including if the other party to the Corporation's hedge does not perform its obligations under the hedge agreement. The Corporation has entered and may in the future enter into hedging arrangements to settle future payments under its equity‑based long term incentive programs, which could result in the Corporation suffering losses to the extent the hedged costs of such arrangements exceed the actual costs that would otherwise be payable at the time of settlement.

 

Unforeseen title defects, disputes or litigation may result in a loss of entitlement to production, reserves and resources.

 

From time to time, the Corporation conducts title reviews in accordance with industry practice prior to purchases of assets. However, if conducted, these reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat the Corporation's title to the purchased assets. If this type of defect were to occur, the Corporation's entitlement to the production and reserves and, if applicable, resources from the purchased assets could be jeopardized. Furthermore, from time to time, the Corporation may have disputes with industry partners as to ownership rights of certain properties or resources, including with respect to the validity of oil and gas leases held by the Corporation or with respect to the calculation or deduction of royalties payable on the Corporation's production. The existence of title defects or the resolution of disputes may have a material adverse effect on the Corporation or its assets and operations. Furthermore, from time to time, the Corporation or its industry partners may owe one another contractual, trust-related or offset obligations which they may default in satisfying and which may adversely affect the validity of an oil and gas lease in which the Corporation has an interest. The existence of title defects, unsatisfied contractual, trust-related or offset obligations, or the resolution of any disputes with industry partners arising from same, may have a material adverse effect on the Corporation or its assets and operations.

 

Dividends and other payments on the Corporation's Common Shares are variable.

 

Although the Corporation currently intends to continue to return cash to shareholders with a monthly cash dividend payment and/or share repurchases, investor returns may change from time to time due to changes in the amount of the cash dividend paid or shares repurchased. With regard to the dividend, cash dividends are declared in Canadian dollars and are 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 weakens with respect to their currency, the amount of the dividend may be reduced when converted to shareholders’ home currency. In addition, shareholders may be subject to withholding taxes in accordance with tax treaties or domestic tax law changes, as determined by shareholder residency.

 

The amount of cash available to the Corporation to pay dividends or repurchase shares can vary significantly from period to period for many reasons including, among other things:

·

the Corporation's operational and financial performance, including fluctuations in the quantity of the Corporation's oil, NGLs and natural gas production and the sales price that the Corporation realizes for such production (after hedging contract receipts and payments)

·

fluctuations in the costs to produce oil, NGLs and natural gas, including royalty burdens, and costs to administer and manage the Corporation and its subsidiaries

·

the amount of cash required or retained for debt service or repayment

·

amounts required to fund capital expenditures and working capital requirements

·

access to equity markets

·

foreign currency exchange rates and interest rates

·

the risk factors set forth in this Annual Information Form

 

The decision whether to pay dividends and the amount of any such dividend is subject to the discretion of the board of directors of the Corporation, which regularly evaluates the Corporation's dividend policy, and the solvency test requirements of the ABCA. In addition, the level of dividends per Common Share will be affected by the number of outstanding Common Shares and other securities that may be entitled to receive cash dividends or other payments. Dividends may be increased, reduced or suspended entirely depending on the Corporation's operations and the performance of its assets. The market

ENERPLUS 2018 ANNUAL INFORMATION FORM     51

 

 

value of the Common Shares may deteriorate if the Corporation is unable to meet dividend expectations in the future, and that deterioration may be material.

 

In addition, to the extent the Corporation uses internally‑generated cash flow to repurchase shares, or finance acquisitions, development costs and other significant capital expenditures, the amount of cash available to pay dividends to the Corporation's shareholders may be reduced. To the extent that external sources of capital, including debt or the issuance of additional Common Shares or other securities of the Corporation, become limited or unavailable, the Corporation's ability to make the necessary capital investments to maintain, develop or expand its oil and gas reserves and resources and to invest in assets may be impaired. To the extent that the Corporation is required to use cash flow to finance capital expenditures, property acquisitions or asset acquisitions, as the case may be, the level of the Corporation's cash dividend payments to its shareholders may be reduced or even eliminated.

 

The board of directors of the Corporation has the discretion to determine the extent to which the Corporation's cash flow will be allocated to the payment of debt service charges as well as the repayment of outstanding debt. The payments of interest and principal with respect to the Corporation's third-party indebtedness, including the Credit Facilities, rank ahead of dividend payments that may be made by the Corporation to its shareholders. An increase in the amount of funds used to pay debt service charges or reduce debt will reduce the amount of cash that may be available for the Corporation to pay dividends, or repurchase shares from its shareholders. In addition, variations in interest rates and scheduled principal repayments, if and as required under the terms of the Credit Facilities, could result in significant changes in the amount required to be applied to debt service. Certain covenants in agreements with lenders may also limit payments of dividends.

 

Fluctuations in foreign currency exchange rates could adversely affect the Corporation's business.

 

The price that the Corporation receives for a majority of its oil and natural gas is based on U.S.‑dollar denominated benchmarks and, therefore, the price that the Corporation receives in Canadian dollars is affected by the exchange rate between the two currencies. Should there be a material increase in the value of the Canadian dollar relative to the U.S. dollar, it may negatively impact the Corporation's net production revenue by decreasing the Canadian dollars the Corporation receives for a given sale in U.S. dollars. The Corporation’s business and operations in Canada and the United States have contracts that are linked to the U.S. dollar and, therefore, the Corporation is exposed to foreign currency risk on both revenues and costs. In addition, the Corporation has U.S.-dollar denominated Senior Unsecured Notes and is exposed to increased foreign currency risk should the Canadian dollar weaken against the U.S. dollar. The Corporation may from time to time use derivative instruments to manage a portion of its foreign exchange risk, as described in   Note 14(c) to the Corporation's Financial Statements.

 

Recent court rulings on the liability surrounding abandonment and reclamation obligations of oil and gas companies may adversely affect the Corporation.

 

As a general rule, the current oil and gas asset abandonment, reclamation and remediation (" A&R ") liability regime in Alberta limits each party's liability to its proportionate ownership of an asset. In the case where one joint owner of an oil and gas asset becomes insolvent and is unable to fund the required A&R activities associated with such asset, the solvent counterparties can recover the insolvent party's share of the remediation costs from the Orphan Well Association (the " OWA "). The OWA administers orphaned assets and is funded through a levy imposed on licensees, including the Corporation, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, wells and unreclaimed sites in Alberta. British Columbia has similar liability management regimes.

 

As a result of the Supreme Court of Canada's January 2019 decision in the case of Redwater Energy Corporation (" Redwater "), a trustee in bankruptcy is not permitted to renounce uneconomic oil and gas assets and leave these assets to be remediated by the OWA, thereby avoiding the environmental liabilities of the estate it is administering. Accordingly, the AER may now use Alberta’s provincial legislative scheme to prevent the repudiation or renunciation of an insolvent company's assets by a trustee and require the trustee to satisfy certain environmental obligations in priority to the claims of secured and unsecured creditors.

 

In response to lower court decisions relating to Redwater, the AER released Bulletin 2016-16 which, among other things, implemented important changes to the AER's procedures relating to liability management ratings, licence eligibility and licence transfers. In addition, changes with respect to licence eligibility were codified in amendments to AER Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals. Among other things, Directive 067 provides the AER with broad discretion to determine if a party poses an "unreasonable risk" such that it should not be eligible to hold AER licences.

 

The British Columbia provincial government has announced similar policies. The BCOGC is also exploring the development of a comprehensive liability management strategy driven in part by the proliferation of orphan sites. The imposition of timelines for cleanup of inactive sites is among the measures under consideration.

 

52      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

These changes may impact the Corporation's ability to transfer its licences, approvals or permits in the course of a divestment, and may result in increased costs and delays or require changes to or abandonment of projects and transactions. As a result of the decision in Redwater, lenders may reduce the availability of credit to oil and gas issuers that utilize secured loans, thereby negatively affecting the financial capacity of such issuers, including potential partners and counterparties of the Corporation. Lenders also may generally increase their scrutiny of oil and gas assets held by producers, including the Corporation, and the associated A&R liabilities in determining whether to provide credit, may require borrowers to adhere to more stringent A&R-related operational covenants, and may increase the cost of providing credit.

The Supreme Court decision in Redwater also could make the transfer of oil and gas assets from insolvent parties more challenging if a trustee in bankruptcy is unable to separate economic assets from uneconomic assets within the insolvent party's estate in order to facilitate a sale process. The result could be additional liabilities being placed upon the OWA. The OWA may seek funding for such liabilities from industry participants, including the Corporation, through an increase in its annual levy, further changes to regulations, or other means. While the impact on the Corporation of any legislative, regulatory or policy decisions as a result of the Redwater decision cannot be reliably or accurately estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact the Corporation and materially and adversely affect, among other things, the Corporation’s business, financial condition, results of operations and cash flow.

Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief.

 

Declines or continued volatility in crude oil and natural gas prices may result in a significant reduction in earnings or cash flow, which could lead the Corporation to increase amounts drawn under the Bank Credit Facility in order to carry out its operations and fulfill its obligations. Significant reductions to cash flow, significant increases in drawn amounts under the Bank Credit Facility, or significant reductions to proved reserves may result in the Corporation breaching its debt covenants under the Credit Facilities. If a breach occurs, there is a risk that the Corporation may not be able to negotiate covenant relief with one or more of its lenders under the Credit Facilities. Failure to comply with debt covenants or negotiate relief may result in the Corporation’s indebtedness under the Credit Facilities becoming immediately due and payable, which may have a material adverse effect on the Corporation’s operations and financial condition.

 

The Corporation's Credit Facilities and any replacement credit facility may not provide sufficient liquidity.

 

Although the Corporation believes that its existing Credit Facilities are sufficient, there can be no assurance that the current amount will continue to be available or will be adequate for the financial obligations of the Corporation or that additional funds can be obtained as required or on terms which are economically advantageous to the Corporation. The amounts available under the Credit Facilities may not be sufficient for future operations, or the Corporation may not be able to renew its Bank Credit Facility or obtain additional financing on attractive economic terms, if at all. The Bank Credit Facility is generally available on a three-year term, extendable each year with a bullet payment required at the end of three years if the facility is not renewed. The Corporation renewed its Bank Credit Facility in 2018 and, accordingly, it currently expires on October 31, 2021. There can be no assurance that such a renewal will be available on favourable terms or that all of the current lenders under the facility will renew at their current commitment levels. If this occurs, the Corporation may need to obtain alternate financing. Any failure of a member of the lending syndicate to fund its obligations under the Bank Credit Facility or to renew its commitment in respect of such Bank Credit Facility, or failure by the Corporation to obtain replacement financing or financing on favourable terms, may have a material adverse effect on the Corporation's business and operations. In addition, dividends to shareholders may be eliminated, as repayment of debt under the Credit Facilities has priority over dividend payments by the Corporation to its shareholders.

 

The Corporation's operations are subject to certain risks and liabilities inherent in the oil and natural gas business, some of which may not be covered by insurance.

 

The Corporation's business and operations, including the drilling of oil and natural gas wells and the production and transportation of oil and natural gas, are subject to certain risks inherent in the oil and natural gas business. These risks and hazards include encountering unexpected formations or pressures, blow‑outs, pipeline breaks, rail transportation incidents, craterings, fires, power interruptions and severe weather conditions. The Corporation's operations may also subject it to the risk of vandalism or terrorist threats, including eco‑terrorism and cyber-attacks. The foregoing hazards could result in personal injury, loss of life, reduced production volumes or environmental and other damage to the Corporation's property and the property of others. The Corporation cannot fully protect against all of these risks, nor are all of these risks insurable. The Corporation may become liable for damages arising from events against which it cannot insure, or against which it may elect not to insure because of high premium costs, or other reasons. While the Corporation has both safety and environmental policies in place to protect its operators and employees, and to meet regulatory requirements in areas where they operate, any costs incurred to repair, damage, or pay liabilities would adversely affect the Corporation's financial position, including the amount of funds that may be available for development programs, debt repayments, or dividend payments to shareholders.

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     53

 

 

The Corporation sets out to hire competent personnel and the loss of such personnel, including the Corporation's management or key personnel, could impact its business.

 

The Corporation’s business and prospects for future success, including the successful implementation of strategies and/or handling of issues integral to its future success, depend to a significant extent upon the continued service and performance of the management team and key personnel. Shareholders are entirely dependent on the management and key personnel of the Corporation with respect to the exploration for and development of additional reserves and resources, the acquisition of oil and natural gas properties and assets, and the management and administration of all matters relating to the Corporation and its properties and assets, including hiring competent personnel. The loss of any member of Enerplus’ management team or other key personnel, and its inability to attract, motivate and retain substitute key personnel with comparable experience and skills, could materially and adversely affect the business, financial condition and results of operations.

 

The increased acceptance of new technology may lead to reputational issues or financial losses.

 

Technologies are often employed to assist, augment, automate or provide autonomous intelligence, which results in reduced reliance on human intervention and/or decision-making and, therefore, may increase the Corporation’s risk of financial or reputational loss.

Conflicts of interest may arise between the Corporation and its directors and officers.

 

Circumstances may arise where directors and officers of the Corporation are directors or officers of other companies involved in the oil and gas industry which are in competition to the interests of the Corporation. See " Directors and Officers – Conflicts of Interest ".

 

The ability of United States and other non‑resident shareholder investors to enforce civil remedies may be limited.

 

The Corporation is formed under the laws of Alberta, Canada, and its principal place of business is in Canada. Most of the directors and officers of the Corporation are residents of Canada and some of the experts who provide services to the Corporation (such as its auditors and some of its independent reserves engineers) are residents of Canada, and a portion of their assets and the Corporation's assets are located within Canada. As a result, it may be difficult for investors in the United States or other non‑Canadian jurisdictions (a " Foreign Jurisdiction ") to effect service of process within such Foreign Jurisdiction upon such directors, officers and representatives of experts who are not residents of the Foreign Jurisdiction or to enforce against them judgments of courts of the applicable Foreign Jurisdiction based upon civil liability under the securities laws of such Foreign Jurisdiction, including U.S. federal securities laws or the securities laws of any state within the United States. In particular, there is doubt as to the enforceability in Canada against the Corporation or any of its directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments by U.S. courts for liability based solely upon the U.S. federal securities laws or the securities laws of any state within the United States.

 

 

Market for Securities

 

The Common Shares are listed and posted for trading on the TSX and the NYSE under the trading symbol "ERF".

 

The following table sets forth certain trading information for the Common Shares on the TSX composite index and the United States composite index for 2018.  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TSX Composite Trading

 

U.S. Composite Trading

Month

    

High

    

Low

    

Volume

    

High

    

Low

    

Volume

January

 

14.54

 

12.20

 

50,163,913

 

11.78

 

9.82

 

31,326,187

February

 

15.06

 

12.18

 

46,248,019

 

11.87

 

9.66

 

20,634,975

March

 

15.90

 

13.53

 

41,559,946

 

12.26

 

10.49

 

18,399,673

April

 

16.01

 

13.79

 

52,005,269

 

12.47

 

10.75

 

20,608,654

May

 

17.21

 

14.50

 

49,304,900

 

13.49

 

11.26

 

23,424,071

June

 

17.07

 

15.12

 

41,199,968

 

12.95

 

11.42

 

23,748,745

July

 

17.73

 

16.30

 

28,924,564

 

13.56

 

12.21

 

14,291,252

August

 

18.04

 

15.95

 

36,067,423

 

13.87

 

12.11

 

14,265,185

September

 

16.39

 

14.51

 

34,761,331

 

12.65

 

11.03

 

12,314,492

October

 

16.57

 

11.68

 

57,356,810

 

12.89

 

8.90

 

18,273,901

November

 

13.37

 

11.92

 

51,942,963

 

9.99

 

9.03

 

22,010,746

December

 

13.70

 

9.65

 

44,130,960

 

10.40

 

6.84

 

26,460,947

 

54      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

 

Directors and Officers

 

DIRECTORS OF THE CORPORATION 

 

The directors of the Corporation are elected by the shareholders of the Corporation at each annual meeting of shareholders. All directors serve until the next annual meeting or until a successor is elected or appointed or until the director is removed at a meeting of shareholders. The name, municipality of residence, year of appointment as a director of the Corporation and principal occupation for the past five years for each current director of the Corporation are set forth below.

 

 

 

 

 

 

Name and Residence

    

Director Since

    

Principal Occupation for Past Five Years

 

 

 

 

 

Elliott Pew (1)
Boerne, Texas, United States

 

September 2010

 

Corporate director.

 

 

 

 

 

Karen E. Clarke-Whistler ( 3 ) (6)
Toronto, Ontario, Canada

 

December 2018

 

Corporate director. Prior thereto, Chief Environment Officer at TD Bank Group until her retirement in 2018.

 

 

 

 

 

Michael R. Culbert (2)(3)(4)
Calgary, Alberta, Canada

 

March 2014

 

Mr. Culbert is Vice Chairman of Petronas  Energy Canada Ltd. (“Petronas Canada”), an oil and gas company, since November 2016. He continues to serve as a non-executive director of Petronas Canada and Precision Drilling Corporation (an oilfield services company).  Prior thereto, he was President and Chief Executive Officer of Petronas Canada. 

 

 

 

 

 

Ian C. Dundas
Calgary, Alberta, Canada

 

July 2013

 

President & Chief Executive Officer of Enerplus since July 2013. Prior thereto, Executive Vice President and Chief Operating Officer of Enerplus from April 2011 to July 2013. 

 

 

 

 

 

Hilary A. Foulkes ( 3 ) (4) (5)(6)(8)
Calgary, Alberta, Canada

 

February 2014

 

Corporate director. Currently Chair, Tudor, Pickering, Holt & Co. Securities – Canada, ULC.

 

 

 

 

 

Robert B. Hodgins (2)(3) (4) (7)
Calgary, Alberta, Canada

 

November 2007

 

Mr. Hodgins is a Senior Advisor, Investment Banking at Canaccord Genuity Corp. since September 2018 and has been an independent businessman since November 2004.

 

 

 

 

 

Susan M. MacKenzie ( 2)(5 )(6)
Calgary, Alberta, Canada

 

July 2011

 

Corporate director. Prior thereto, independent consultant from 2010 to 2015.

 

 

 

 

 

Glen D. Roane (2)(3) (9)
Canmore, Alberta, Canada

 

June 2004

 

Corporate director.

 

 

 

 

 

Jeffrey W. Sheets (2)( 4 ) (6)
Houston, Texas, United States

 

December 2017

 

Corporate director. Prior thereto, Executive Vice President and Chief Financial Officer of ConocoPhilips Company from October 2010 to February 2016.

 

 

 

 

 

Sheldon B. Steeves ( 5 )( 6 )
Calgary, Alberta, Canada

 

June 2012

 

Corporate director.

 

 

 

 

 

 

 

 

 

 

 

Notes:

(1)

Chairman of the board of directors and ex officio member of all committees of the board of directors.

(2)

The Audit & Risk Management Committee is currently comprised of Robert B. Hodgins as Chair, Michael R. Culbert, Susan M. MacKenzie, Glen D. Roane,  and Jeffrey W. Sheets.

(3)

The Corporate Governance & Nominating Committee is currently comprised of Glen D. Roane as Chair, Michael R. Culbert, Karen E. Clarke-Whistler, Hilary A. Foulkes and Robert B. Hodgins.

(4)

The Compensation & Human Resources Committee is currently comprised of Michael R. Culbert as Chair, Hilary A. Foulkes, Robert B. Hodgins and Jeffrey W. Sheets.

(5)

The Reserves Committee is currently comprised of Sheldon B. Steeves as Chair, Hilary A. Foulkes and Susan M. MacKenzie.

(6)

The Safety & Social Responsibility Committee is currently comprised of Susan M. MacKenzie as Chair, Karen E. Clarke-Whistler, Hilary A. Foulkes, Jeffrey W. Sheets and Sheldon B. Steeves.

(7)

Mr. Hodgins was a director of Skope Energy Inc. ("Skope") from December 15, 2010 to February 19, 2013. On November 27, 2012, Skope was granted protection from its creditors by the Court of Queen's Bench of Alberta pursuant to the CCAA to implement a restructuring which was approved by the required majority of Skope's creditors. The restructuring was sanctioned by the Court of Queen's Bench of Alberta in February of 2013.

(8)

Ms. Foulkes was a director of Parallel Energy Trust (“Parallel”). On November 9, 2015, Parallel and its affiliated entities filed an application for protection under the CCAA and voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court of Delaware. Ms. Foulkes ceased to be a director of Parallel on March 1, 2016. Parallel filed an assignment in bankruptcy and proceedings under the CCAA were terminated in March 2016. 

(9)

Mr. Roane will not be standing for re-election at the Annual Meeting to be held on May 9, 2019.

ENERPLUS 2018 ANNUAL INFORMATION FORM     55

 

 

 

OFFICERS OF THE CORPORATION

 

The name, municipality of residence, position held and principal occupation for the past five years for each officer of the Corporation are set out below.

 

Name and Residence

    

Office

    

Principal Occupation for Past Five Years

 

 

 

 

 

Ian C. Dundas
Calgary, Alberta, Canada

 

President & Chief Executive Officer

 

President & Chief Executive Officer of the Corporation.

 

 

 

 

 

Jodine J. Jenson Labrie
Calgary, Alberta, Canada

 

Senior Vice President & Chief Financial Officer

 

Senior Vice President & Chief Financial Officer of the Corporation since September 2015. Prior thereto, Vice President, Finance of the Corporation since July 2013.

 

 

 

 

 

Raymond J. Daniels
Calgary, Alberta, Canada

 

Senior Vice President, Operations, People & Culture

 

Senior Vice President, Operations, People & Culture of the Corporation since January 2017. Prior thereto, Senior Vice President, Operations of the Corporation.

 

 

 

 

 

Garth R. Doll
Calgary, Alberta, Canada

 

Vice President, Marketing

 

Vice President, Marketing of the Corporation since February 2019. Prior thereto, Manager, Marketing of the Corporation since 2013.

 

 

 

 

 

Terry S. Eichinger
Calgary, Alberta, Canada

 

Vice President, U.S. Operations & Engineering

 

Vice President, U.S. Operations & Engineering of the Corporation since September 2018. Prior thereto, Senior Manager, U.S. Operations & Engineering of the Corporation since May 2014 and Manager, Deep Gas of the Corporation since May 2011.

 

 

 

 

 

Nathan D. Fisher
Denver, Colorado, United States

 

Vice President, U.S. Development & Geosciences

 

Vice President, U.S. Development & Geosciences of the Corporation since September 2015.  Prior thereto, Manager, Geology & Geophysics for U.S. Operations of the Corporation since April 2011. 

 

 

 

 

 

Daniel J. Fitzgerald
Calgary, Alberta, Canada

 

Vice President, Business Development

 

Vice President, Business Development of the Corporation since September 2015.  Prior thereto, Manager, Business Development & Strategic Planning of the Corporation.

 

 

 

 

 

John E. Hoffman
Calgary, Alberta, Canada

 

Vice President, Canadian Operations

 

Vice President, Canadian Operations of the Corporation since April 2015.  Prior thereto, General Manager, North America Onshore at Suncor Energy Inc. 

 

 

 

 

 

David A. McCoy
Calgary, Alberta, Canada

 

Vice President, General Counsel & Corporate Secretary

 

Vice President, General Counsel & Corporate Secretary of the Corporation.

 

 

 

 

 

Edward L. McLaughlin
Denver, Colorado, United States

 

President, U.S. Operations

 

President, U.S. Operations of the Corporation. 

 

 

 

 

 

Shaina B. Morihira
Calgary, Alberta, Canada

 

Vice President, Finance

 

Vice President, Finance of the Corporation since February 2018. Prior thereto, Corporate Controller of the Corporation since July 2015. Prior thereto, Controller, Financial of Progress Energy Canada Ltd. from January 2015 to July 2015. Prior thereto, Manager, Financial Reporting of Progress Energy.

 

 

 

 

 

 

 

COMMON SHARE OWNERSHIP 

 

As of February 20, 2019, the directors and officers of the Corporation named above beneficially own, or control or exercise direction over, directly or indirectly, an aggregate of 858,747 Common Shares, representing approximately 0.4% of the outstanding Common Shares as of that date.

 

56      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

CONFLICTS OF INTEREST 

 

Certain of the directors and officers named above may be directors or officers of issuers or other companies which are in competition with the Corporation, and as such may encounter conflicts of interest in the administration of their duties with respect to the Corporation. In situations where conflicts of interest arise, the Corporation expects the applicable director or officer to declare the conflict and, if a director of the Corporation, abstain from voting in respect of such matters on behalf of the Corporation.

 

See " Risk Factors – Conflicts of interest may arise between the Corporation and its directors and officers ".

 

AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE 

 

The disclosure regarding the Corporation's Audit & Risk Management Committee required under National Instrument 52‑110 adopted by the Canadian securities regulatory authorities is contained in Appendix D to this Annual Information Form.

 

 

 

Legal Proceedings and Regulatory Actions

 

The Corporation is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Corporation's favour, the Corporation does not currently believe that the outcome of any pending or threatened proceedings related to these or other matters, or the amounts which the Corporation may be required to pay by reason thereof, would have a material adverse impact on its financial position, results of operations or liquidity. Notwithstanding the above, the Corporation is aware of a class action filed in Fort Berthold Tribal Court in November 2017 as Civil Action No. 2017-0505 against the Corporation and fifteen other companies operating on the FBIR (the “Action”). The plaintiffs in the Action are members of the Three Affiliated Tribes who own mineral interests on the FBIR and allege that the defendant companies have committed trespass, failed to pay royalties properly, etc. They seek judgement against the defendant group for $585 million in damages, $500 million in punitive damages, and disgorgement of the value of oil and gas produced from the plaintiffs’ property. The Corporation believes the claim, as against the Corporation, is without merit.

 

 

Interest of Management and Others in Material Transactions 

 

To the knowledge of the directors and executive officers of the Corporation, none of the directors or executive officers of the Corporation and no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over, more than 10% of any class or series of the Corporation's securities, nor any associate or affiliate of any of the foregoing, has had any material interest, direct or indirect, in any transaction with the Corporation since January 1, 2016 or in any proposed transaction that has materially affected or is reasonably expected to materially affect Enerplus.

 

 

 

Material Contracts and Documents Affecting the Rights of Securityholders

 

The Corporation is not a party to any contracts material to its business or operations, other than contracts entered into in the normal course of business.

 

Copies of the following documents entered in the normal course of business and relating to the Credit Facilities have been filed on the Fund's SEDAR profile at  www.sedar.com and on Form 6‑K on the Fund's EDGAR profile at  www.sec.gov , if they were filed prior to the January 1, 2011 Conversion, and on the Corporation's SEDAR profile at  www.sedar.com and on Form 6‑K on the Corporation's EDGAR profile at  www.sec.gov , if they were filed on or after the January 1, 2011 Conversion:

 

1.

Amended and Restated Bank Credit Facility (November 5, 2012); the First Amending Agreement relating thereto (January 13, 2014); the Second Amending Agreement relating thereto (May 13, 2014); the Third Amending Agreement relating thereto (SEDAR – December 1, 2014; EDGAR – December 9, 2014); the Fourth Amending Agreement relating thereto (November 6, 2015); the Fifth Amending Agreement relating thereto (November 7, 2016); and the Sixth Amending Agreement relating thereto (November 8, 2018);

 

2.

Form of the Note Purchase Agreement for the Senior Unsecured Notes issued in 2009 (SEDAR – June 23, 2009; EDGAR – June 25, 2009);

ENERPLUS 2018 ANNUAL INFORMATION FORM     57

 

 

 

3.

Form of the Note Purchase Agreement for the Senior Unsecured Notes issued in 2012 (SEDAR – May 23, 2012; EDGAR – May 24, 2012); and

 

4.

Form of the Note Purchase Agreement for the Senior Unsecured Notes issued in 2014 (SEDAR – October 10, 2014; EDGAR – October 15, 2014).

 

Copies of the following documents affecting the rights of securityholders have been filed on the Corporation's SEDAR profile at  www.sedar.com and on Form 6‑K on the Corporation's EDGAR profile at  www.sec.gov .

 

1.

the Articles of Amalgamation (January 2, 2013); By-law No. 1 of the Corporation (June 16, 2014); and By-law No. 2 of the Corporation (May 6, 2016); and

 

2.

the Shareholder Rights Plan, as described under "Description of Capital Structure – Shareholder Rights Plan" (May 6, 2016).

 

 

Interests of Experts

 

McDaniel prepared the McDaniel Reports in respect of certain reserves attributable to the Corporation's oil and natural gas properties in Canada and the western United States, a summary of which is contained in this Annual Information Form, and reviewed certain reserves evaluated internally by the Corporation. McDaniel also audited the internal estimates of contingent resources attributable to the Corporation's interests in the Fort Berthold, North Dakota area, and certain of its waterflood assets located in Alberta and Saskatchewan, which are referred to in this Annual Information Form in Appendix A. As of the dates of the McDaniel Reports, the "designated professionals" (as defined in Form 51‑102F2 – Annual Information Form of the Canadian securities regulatory authorities) of McDaniel, as a group, beneficially owned, directly or indirectly, no outstanding Common Shares. NSAI prepared the NSAI Report in respect of the reserves and contingent resources attributable to the Corporation's interests in the Marcellus property, a summary of which is contained in this Annual Information Form. As of the dates of the NSAI Report, the designated professionals of NSAI, as a group, beneficially owned, directly or indirectly, no outstanding Common Shares.

 

KPMG LLP (“ KPMG ”) was appointed as the auditors of the Corporation on May 31, 2017 and have confirmed with respect to the Corporation, that they are independent within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations, and also that they are independent accountants with respect to the Corporation under all relevant U.S. professional and regulatory standards. Deloitte LLP (“ Deloitte ”) was the independent registered public accounting firm of the Corporation for the years ended December 31, 2016. Throughout the periods covered by the financial statements of the Corporation on which they reported, Deloitte was independent within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules and standards of the Public Company   Accounting Oversight Board and the securities laws and regulations administered by the SEC.  

 

 

Transfer Agent and Registrar

 

The transfer agent and registrar for the Common Shares in Canada is Computershare Trust Company of Canada, at its principal offices in Calgary, Alberta and Toronto, Ontario. Computershare Trust Company N.A. at its principal offices in Golden, Colorado is the transfer agent for the Common Shares in the United States.

 

 

Additional Information 

 

Additional information relating to the Corporation may be found on the Corporation's profile on the SEDAR website at  www.sedar.com , on the EDGAR website at  www.sec.gov and on the Corporation's website at  www.enerplus.com . Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Corporation's securities and securities authorized for issuance under equity compensation plans, as applicable, will be contained in the Corporation's information circular and proxy statement with respect to its 2019  annual meeting of shareholders. Furthermore, additional financial information relating to the Corporation is provided in the Corporation's audited consolidated financial statements and MD&A. Shareholders who wish to receive printed copies of these documents free of charge should contact the Corporation's Investor Relations Department using the contact information on the back cover of this Annual Information Form.

 

 

58      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

APPENDIX A

 

 

Appendix A – Contingent Resources Information

 

NOTE TO READER REGARDING DISCLOSURE OF CONTINGENT RESOURCES INFORMATION

 

All of the Corporation's contingent resources have been evaluated in accordance with NI 51-101. NSAI, an independent petroleum consulting firm based in Dallas, Texas, has evaluated the Corporation's contingent resources attributable to its Marcellus properties located in Pennsylvania, United States, using the average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2019. The Corporation has evaluated the balance of its U.S. properties located in North Dakota, United States, and its Canadian properties located in Alberta and Saskatchewan to which contingent resources have been assigned using similar evaluation parameters, including the same forecast price, inflation and exchange rate assumptions utilized by McDaniel, which as required by NI 51-101 has audited the Corporation's internal evaluation of these properties.

 

The following sections and tables summarize, as at December 31, 2018, the Corporation's "best estimate" (as defined below) contingent resources, including risked contingent resource volumes and risked net present value of future net revenue of contingent resources in development pending project maturity sub-class, together with certain information, estimates and assumptions associated with such estimates. The data contained in the tables is a summary of the evaluations, and as a result the tables may contain slightly different numbers than the evaluations themselves due to rounding. Additionally, the columns and rows in the tables may not add due to rounding. 

 

All estimates of future net revenues are stated prior to provision for interest and general and administrative expenses and after deduction of royalties and estimated future capital expenditures, and are presented before deducting income taxes. For additional information, see " Business of the Corporation – Tax Horizon ", " Industry Conditions " and " Risk Factors " in the Annual Information Form.

 

With respect to pricing information in the following resources information, the wellhead oil prices were adjusted for quality and transportation based on historical actual prices. The natural gas prices were adjusted, where necessary, based on historical pricing based on heating values and transportation. The NGLs prices were adjusted to reflect historical average prices received.

 

The estimated future net revenue to be derived from the production of the contingent resources set out in this Appendix A is based on the average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2019, and was utilized by NSAI and by the Corporation in its internal evaluations for consistency in the Corporation's reporting, and the inflation and exchange rate assumptions set forth under " Oil and Natural Gas Reserves – Forecast Prices and Costs " in the Annual Information Form.  Also see " Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information – Description of Price and Cost Assumptions " in the Annual Information Form. 

 

It should not be assumed that the summary of risked net present value of estimated future cash flows shown in the tables below is representative of the fair market value of the contingent resources. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and contingent resources estimates of the Corporation's crude oil, natural gas liquids and natural gas contingent resources provided herein are estimates only. Actual resources may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained below .

 

Contingent Resources Categories and Levels of Certainty for Reported Resources

 

In this Appendix A, the Corporation has disclosed estimated volumes of economic "contingent resources" which relate to the Corporation's interests in its Fort Berthold property located in North Dakota, its Marcellus shale gas property located in Pennsylvania, and certain of its crude oil properties located in Alberta and Saskatchewan.

 

" resources " are petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including discovered and undiscovered (recoverable and unrecoverable) plus quantities already produced.

 

" contingent resources " are defined as 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 project stage. "Economic" contingent resources are those resources that are economically recoverable based on the average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2019.  

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     A-1

 

 

The economic contingent resources estimates in this Appendix A are presented as the " best estimate " of the quantity that will actually be recovered, meaning that it is equally likely that the actual remaining quantities recovered will be greater or less than the “best estimate”, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the “best estimate”.

 

" risked " means that the applicable volumes or revenues have been adjusted for the probability of loss or failure in accordance with the COGEH.  See " Description of Properties " below. 

 

Resources and contingent resources do not constitute, and should not be confused with, reserves. See " Business of the Corporation – Description of Properties " and " Risk Factors – The Corporation's actual reserves and resources will vary from its reserves and resources estimates, and those variations could be material ".

 

Contingent Resources Development Status

 

Contingent resources may be divided into the following project maturity sub-classes:

 

" development pending "   resources sub-class is assigned to contingent resources for a particular project where resolution of the final conditions for development is being actively pursued (there is a high chance of development) and the project is expected to be developed in a reasonable timeframe;

 

" development on hold" resources sub-class is assigned to contingent resources for a particular project 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 "   resources are those for which additional information is being acquired;

 

" development not viable " resources are those where no further data acquisition or evaluation is currently planned and there is a low chance of development. 

 

All of the Corporation's contingent resources fall into the "development pending" sub-class.

 

CONTINGENT RESOURCES DATA 

 

The following tables set forth the "best estimate" of gross and net risked contingent resources volumes and risked net present value of future net revenue attributable to the Corporation's contingent resources in the development pending project maturity sub-class, at December 31, 2018, using forecast price and cost cases. An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation 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 no certainty that the estimate of risked net present value of future net revenue will be realized.

 

Summary of Risked Oil and Gas

Contingent Resources (Forecast Prices and Costs)

As of December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONTINGENT RESOURCES

PROJECT MATURITY SUB-CLASS

 

Light &
Medium Oil

 

Heavy Oil

 

Tight Oil

 

Natural Gas
Liquids

 

Conventional
Natural Gas

 

Shale Gas

 

Total

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(MMcf)

 

(MMcf)

 

(MMcf)

 

(MMcf)

 

(MBOE)

 

(MBOE)

Development Pending

 

2,861

 

2,467

 

22,325

 

18,971

 

53,088

 

42,473

 

5,862

 

4,690

 

777

 

672

 

589,076

 

471,262

 

182,446

 

147,257

 

Risked Net Present Value of Future Net Revenue

Contingent Resources (Forecast Prices and Costs)

As of December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

RISKED NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/Year)

 

 

Before Deducting Income Taxes

PROJECT MATURITY SUB-CLASS

    

0%

 

5%

 

10%

 

15%

 

20%

 

 

(in $ millions)

Development Pending

 

3,611.1

 

1,722.7

 

910.1

 

514.3

 

299.9

 

A-2      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

DESCRIPTION OF PROPERTIES 

 

Outlined below is a description of the Corporation's "best estimate" of economic contingent resources for its Canadian and U.S. crude oil and natural gas properties and assets. There is no certainty it will be commercially viable to produce, or that the Corporation will produce, any portion of the volumes currently classified as "contingent resources".

 

Canadian Crude Oil Properties

 

The Corporation has conducted an internal evaluation of the contingent resources associated with a portion of its crude oil waterflood properties which has resulted in an unrisked "best estimate" of 31.6 MMBOE (25.3 MMBOE risked) being classified as economic contingent resources effective as of December 31, 2018. The unrisked net present value of future net revenue, discounted at 10%, of these contingent resources is $303.5 million ($242.8   million risked). This internal evaluation has been independently audited by McDaniel. Improved oil recovery from four existing waterfloods through optimization work accounts for approximately 11.1 MMBOE of the total volumes,  7.6 MMBOE from areas producing heavy crude oil and 3.6 MMBOE from areas producing light or medium crude oil. Approximately 20.4 MMBOE of the total is attributable to heavy crude oil EOR projects in the Corporation's Giltedge property and the Medicine Hat Glauconitic "C" East Unit where polymer flood projects are underway. To implement the projects to recover the contingent resources, it is estimated that $629.1 million of capital will be required. For the improved oil recovery projects, this capital will be spent from 2020 to 2026, and from 2019 to 2045 for the EOR polymer flood projects. As work proceeds and assessed results continue to support the economic viability of these projects, each year a portion of contingent resources is anticipated to be reclassified as reserves. Although further EOR projects are being contemplated on certain of the Corporation's other Canadian crude oil properties, these have not been fully evaluated and no contingent resources have been assessed. 

 

Significant positive factors embedded in this estimate include well‑established waterflood technology, a long history of waterflood performance data and success with the EOR projects that have been implemented. The EOR estimates are based on incremental recovery from higher displacement efficiency without any improvement in areal sweep. A significant negative factor relevant to this estimate is the geological complexity and its effect on injector producer connectivity. These resources are all classified into "development pending" project maturity sub-class as the Corporation is actively pursuing these projects. The chance of development is estimated to be 80% for the waterflood contingent resources based on the favourable results to date and the slight variability of the reservoirs. The contingency preventing these resources from being classified as reserves is the early stage of implementation to the specific waterfloods and the lack of internal approvals for full field implementation. There are several inherent risks and contingencies associated with the development of these properties, including the Corporation's ability to make the necessary capital expenditures to develop the properties, reliance on the Corporation's industry partners in project development, acquisitions, funding and provision of services and those other risks and contingencies described above and that apply generally to oil and gas operations as described above and under " Risk Factors " in the Annual Information Form.

 

U.S. Crude Oil Properties

 

An evaluation of the Corporation's interests in the Bakken and Three Forks formations at Fort Berthold, North Dakota conducted internally by the Corporation and audited by McDaniel has attributed an unrisked "best estimate" of 70.9   MMBOE (63.8 MMBOE risked) of economic contingent resources attributable to these formations, effective as of December 31, 2018, a decrease of approximately 10% from the estimate as of December 31, 2017. The decrease compared to 2017 was the result of 12.5   MMBOE of  unrisked contingent resources being converted to undeveloped reserves, offset by positive revisions to previous estimates of 4.2 MMBOE unrisked contingent resources. The recovery of these tight oil contingent resources is under a primary solution gas drive through horizontal wells completed with multiple fracture treatments. These contingent resources represent approximately 135.6 net future drilling locations over and above 130.2 net booked drilling locations identified in the Corporation's booked proved plus probable reserves. The capital required to drill these locations is estimated to be US$1,157.8 million (or CDN$1,435.2 million) between 2022 and 2025. These estimates are based primarily upon a drilling density of up to 10 wells per drilling spacing unit in the Bakken and Three Forks formations combined. The contingent resources average expected ultimate recovery per well is estimated at 535 MBOE. These contingent resources are economic using established technologies and under current forecast commodity prices. Given the drilling density to date, these contingent resources represent a non‑reserve land utilization of 100% for the operated lands. All of these contingent resources are classified into "development pending" project maturity sub-class, with an estimated chance of development of 90% as their development is expected to immediately follow the reserves development. After application of the chance of development, the risked NPV discounted at 10% is CDN$408.0 million. The Corporation has approximately 194 net reserves wells currently on production in this area. 

 

The primary contingencies which currently prevent the classification of the Corporation's disclosed contingent resources associated with the Fort Berthold, North Dakota property as reserves consist of i)  a  lack of corporate approval for development, and ii) undeveloped reserves. Significant positive factors related to the estimate include continued advancement of drilling and completion technology, and performance of producing wells that continues to exceed expectations resulting in positive revisions to reserves. Another factor related to the estimate is the limited long‑term

ENERPLUS 2018 ANNUAL INFORMATION FORM     A-3

 

 

performance history in the immediate area of the contingent resources. There are a number of inherent risks and contingencies associated with the development of the interests in the property including commodity price fluctuations, project costs, the Corporation's ability to make the necessary capital expenditures to develop the properties, reliance on industry partners in project development, funding and provision of services and those other risks and contingencies described above and that apply generally to oil and gas operations as described above and under " Risk Factors " in the Annual Information Form.

 

U.S. Natural Gas Properties

 

NSAI has conducted an independent assessment of the contingent resources attributable to the Corporation's interests in the Marcellus property and has provided an unrisked "best estimate" of economic shale gas contingent resources of approximately 699.7 Bcf (559.8 Bcf risked) at December 31, 2018. The unrisked NPV associated with these contingent resources is CDN$324.1 million (CDN$259.3 million risked). Approximately 129.6 Bcf of contingent resources were reclassified as reserves in 2018. The remaining contingent resources are economic based on the forecast price and cost assumptions used for the Corporation's year‑end 2018 reserves evaluations. This estimate represents a non-reserve land utilization rate of 95% and average well ultimate recovery of approximately 13.1 Bcf. These contingent resources are classified into "development pending" project maturity sub-class as it is anticipated their development will be a continuation of the current reserves development. These contingent resources have an estimated 80% chance of development. It is also estimated that US$359.2 million (or CDN$444.6 million) of capital will be required to develop these contingent resources with multifractured horizontal wells, and development will occur from 2024 to 2030. The primary contingencies which currently prevent the classification of the Corporation's disclosed contingent resources associated with its Marcellus interests as reserves consist of additional delineation drilling to confirm economic productivity in the immediate vicinity of the development areas, limitations to development based on adverse topography or other surface restrictions, the uncertainty regarding marketing and transportation of natural gas from development areas, the receipt of all required regulatory permits and approvals to develop the land, and limited access to confidential information of other operators in the Marcellus formation that would support the recognition of reserves on the Corporation's areas of interest. Significant negative factors related to the estimate include the following: the pace of development, including drilling and infrastructure, is slower than the forecast, risk of adverse regulatory and tax changes, and other issues related to gas development in populated areas. There are a number of inherent risks and contingencies associated with the development of the Corporation's interests in the Marcellus property including commodity price fluctuations, project costs, the Corporation's ability to make the necessary capital expenditures to develop the properties, reliance on the Corporation's industry partners in project development, funding and provision of services and those other risks and contingencies described above and that apply generally to oil and gas operations as described above and under " Risk Factors " in the Annual Information Form.

 

 

A-4      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

APPENDIX B

 

 

Appendix B – Report on Reserves Data and Contingent Resources Data by Independent Qualified Reserves Evaluator or Auditor

 

To the board of directors of Enerplus Corporation (the “Corporation”):

 

1.

We have audited, evaluated and reviewed, as applicable, the Corporation’s reserves data and contingent resources data as at December 31, 2018. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2018, 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, 2018, estimated using forecast prices and costs.

 

2.

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

 

3.

We carried out our audit, evaluation and review, as applicable, 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 audit, evaluation and review, as applicable, to obtain reasonable assurance as to whether the reserves data and contingent resources data are free of material misstatement.  An audit, evaluation and review also includes assessing whether the reserves data and contingent resources data are in accordance with principles and definitions presented in the COGE Handbook.

 

5.

The following table sets forth 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 Corporation evaluated and reviewed for the year ended December 31, 2018, and identifies the respective portions thereof that we have evaluated and reviewed and reported on to the Corporation’s management:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Independent

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Qualified

 

 

 

 

 

Net Present Value of Future Net Revenue

Reserves

 

Effective Date of

 

 

 

(before income taxes, 10% discount rate)

Evaluator

 

Evaluation or Review

 

Location of

 

(in $ thousands)

or Auditor

  

Report

  

Reserves

 

Audited

 

Evaluated

    

Reviewed

 

Total

McDaniel & Associates Consultants Ltd.

 

December 31, 2018

 

Canada

 

-

 

$

503,295.6

$

 

217,509.0

 

$

720,804.6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

McDaniel & Associates Consultants Ltd.

 

December 31, 2018

 

North Dakota, Montana & Colorado, USA

 

-

 

US$

2,416,815.2

(1)

 

-

 

US$

2,416,815.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Netherland, Sewell & Associates, Inc.

 

December 31, 2018

 

Pennsylvania, USA

 

-

 

US$

678,799.0

(1)

 

-

 

US$

678,799.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TOTALS

 

 

 

 

 

 

 

$

4,364,593.6

 

$

217,509.0

 

$

4,582,102.6

 

(1)    Future net revenue in $US was converted to $Cdn using the average of the forecast exchange rates of GLJ, McDaniel and Sproule as of January 1, 2019.  These are: 0.757 for 2019, 0.782 for 2020, 0.797 for 2021, 0.803 for 2022, 0.807 for 2023 and 0.808 thereafter.

 

6.

The following table sets 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 Corporation’s statement prepared in accordance with Form 51-101F1 and identifies the respective portions of the contingent resources that we have audited and evaluated and reported on to the Corporation’s management:

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     B-1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Independent

 

Effective

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Qualified

 

Date of

 

Location of

 

 

 

Risked Net Present Value of Future Net Revenue

 

 

Reserves

 

Audit or

 

Resources

 

Risked

 

(before income taxes, 10% discount rate)

 

 

Evaluator

 

Evaluation

 

Other than

 

Volume

 

(in $ thousands)

Classification

    

or Auditor

  

Report

  

Reserves

   

(MMBOE)

    

Audited

    

Evaluated

    

Total

Development Pending Contingent Resources (2C)

 

McDaniel & Associates Consultants Ltd.

 

December 31, 2018

 

Canada

 

25.3

 

$

242,769.0

$

 -

$

 

242,769.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development Pending Contingent Resources (2C)

 

McDaniel & Associates Consultants Ltd.

 

December 31, 2018

 

North Dakota, USA

 

63.8

 

$US

330,218.8

$

 -

$US

 

330,218.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development Pending Contingent Resources (2C)

 

Netherland, Sewell & Associates, Inc.

 

December 31, 2018

 

Pennsylvania, USA

 

93.3

 

$

 -

$US

209,531.1

$US

 

209,531.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7.

In our opinion, the reserves data and contingent resources data, respectively, audited and 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 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 respective effective dates of our reports.

 

9.

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.

 

10.

Executed as to our report referred to above:

 

 

 

 

MCDANIEL & ASSOCIATES CONSULTANTS LTD.

 

NETHERLAND, SEWELL & ASSOCIATES, INC.

“signed by B. Hamm”

    

“signed by C. H. (Scott) Rees III”

B. Hamm, P.Eng.

 

C. H. (Scott) Rees III, P.E.

President & Managing Director

 

Chairman and Chief Executive Officer

 

 

 

Calgary, Alberta, Canada

 

Texas Registered Engineering Firm F-2699

 

 

Dallas, Texas, USA

 

 

 

February 21, 2019

 

February 21, 2019

 

 

 

 

B-2      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

APPENDIX C

 

Appendix C – Report of Management and Directors on Oil and Gas Disclosure 

 

Terms to which a meaning is described in CSA Staff Notice 51‑324 – Glossary to NI 51‑101 Standards of Disclosure for Oil and Gas Activities have the same meaning herein.

 

Management of Enerplus Corporation (the "Corporation") is responsible for the preparation and disclosure of information with respect to the Corporation's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data and contingent resources data.

 

Independent qualified reserves evaluators have evaluated, reviewed and audited, as applicable, the Corporation's reserves data and contingent resources data. The report of the independent qualified reserves evaluators is presented as Appendix B to this Annual Information Form.

 

The Reserves Committee of the board of directors of the Corporation has:

 

(a)

reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluators

 

(b)

met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation and

 

(c)

reviewed the reserves data and contingent resources data with management and the independent qualified reserves evaluators

 

The Reserves Committee of the board of directors of the Corporation has reviewed the Corporation'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 of the Corporation 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 evaluators on the reserves and 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.

 

ENERPLUS CORPORATION

    

 

 

 

 

" Ian C. Dundas "

 

" John E. Hoffman "

Ian C. Dundas

 

John E. Hoffman

President & Chief Executive Officer

 

Vice President, Canadian Operations

 

 

 

 

 

 

" Elliott Pew "

 

" Sheldon B. Steeves "

Elliott Pew

 

Sheldon B. Steeves

Director

 

Director

 

 

 

February 22, 2019

 

 

 

 

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     C-1

 

APPENDIX D

 

 

Appendix D – Audit & Risk Management Committee Disclosure Pursuant to National Instrument 52‑110 

 

A. THE AUDIT & RISK MANAGEMENT COMMITTEE'S CHARTER

 

The charter of the Audit & Risk Management Committee (the " Committee ") of the board of directors of the Corporation is included in this Appendix D.

 

B. COMPOSITION OF THE AUDIT & RISK MANAGEMENT COMMITTEE

 

The current members of the Committee are Robert B. Hodgins (Chairman), Michael. R. Culbert, Susan M. MacKenzie, Glen D. Roane and Jeffrey W. Sheets. Each member of the Committee is independent and financially literate within the meaning of National Instrument 52‑110. Mr. Roane will not be standing for re-election as a director of the Corporation at the annual meeting of the Corporation’s shareholders to be held on May 9, 2019.

 

C. RELEVANT EDUCATION AND EXPERIENCE

 

Name (Director Since)

    

Principal Occupation and Biography

 

 

 

Robert B. Hodgins
(Honors B.A. (Business), CPA, CA)

(Director since November 2007)

Other Public Directorships

     AltaGas Ltd. (energy midstream services)

     Gran Tierra Energy Inc. (international oil and gas exploration and production company)

     MEG Energy Corp. (oil sands company)

 

Mr. Hodgins is a Senior Advisor, Investment Banking at Canaccord Genuity Corp. since September 2018 and has been an independent businessman since November 2004. Prior to that, Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy Trust (a TSX and NYSE‑listed energy trust) from 2002 to 2004. Prior to that, Mr. Hodgins held the position of Vice President and Treasurer of Canadian Pacific Limited (a diversified energy, transportation and hotels company) from 1998 to 2002 and was Chief Financial Officer of TransCanada PipeLines Limited (a TSX and NYSE‑listed energy transportation company) from 1993 to 1998. Mr. Hodgins received an Honors Bachelor of Arts in Business from the Richard Ivey School of Business at the University of Western Ontario in 1975 and received a Chartered Accountant designation and was admitted as a member of the Institute of Chartered Accountants of Ontario in 1977 and Alberta in 1991.

 

 

 

 

 

 

Michael R. Culbert

(B.Sc. (Business Administration))

(Director since February 2014)

 

Other Public Directorships

     Precision Drilling Corporation

 

 

Mr. Culbert is Vice Chairman of Petronas Energy Canada Ltd. (“Petronas Canada”), an oil and gas company, since November 2016. He continues to serve as a director on the boards of Petronas Canada in a non-executive capacity and Precision Drilling Corporation (an oilfield services company). Prior thereto, he was President and Chief Executive Officer of Petronas Canada. 

 

D-1      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

Name (Director Since)

    

Principal Occupation and Biography

 

 

 

 

Susan M. MacKenzie
(B. Eng. (Mechanical), MBA)

(Director since July 2011)

Other Public Directorships

     Freehold Royalties Ltd. (oil and gas royalty focused company)

     Precision Drilling Corporation (oil and gas services company)

     TransGlobe Energy Corporation (oil and gas company)

 

 

 

 

Ms. MacKenzie has over 26 years of energy sector experience, most recently serving as Chief Operating Officer with Oilsands Quest Inc. in 2010, and currently serves as a director of Enerplus, Freehold Royalties Ltd., a Canadian oil and gas royalty focused company, Precision Drilling Corporation, an oil and gas services company, and TransGlobe Energy Corporation, a Canadian oil and gas company. Prior to that, Ms. Mackenzie enjoyed a 12-year career at Petro-Canada where she held senior roles including Vice-President of Human Resources and Vice President of In Situ Development & Operations. Ms. MacKenzie was also with Amoco Canada for 14 years in a variety of engineering and leadership roles in natural gas, conventional oil and heavy oil exploitation. Ms. MacKenzie is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA) and holds the ICD.D. designation from the Institute of Corporate Directors.

 

 

 

Glen D. Roane

(B.A., MBA)

(Director since June 2004)

Other Public Directorships

     Badger Daylighting Ltd. (provider of non‑destructive excavation services)

     Crown Capital Partners, Inc. (financing company)

 

Mr. Roane is a corporate director and currently serves as a director of Enerplus, Badger Daylighting Ltd., and Crown Capital Partners, Inc.  Previously, he served as a board member of a number of TSX-listed energy/resources companies.  Mr. Roane also served two terms as a Member of the Alberta Securities Commission. Mr. Roane retired from TD Asset Management Inc., a subsidiary of the Toronto-Dominion Bank in 1997. Mr. Roane is a director of GBC American Growth Fund Inc., a Canadian mutual fund corporation. Mr. Roane holds a Bachelor of Arts and an MBA from Queen's University in Kingston, Ontario and also holds the ICD.D designation from the Institute of Corporate Directors.

 

 

 

 

Jeffrey W. Sheets
(B.Sc. (Chemical Engineering), MBA (Finance))

(Director since December 2017)

Other Public Directorships

     Westlake Chemical Corporation (chemicals and plastics sales and manufacturing)

 

 

 

Mr. Sheets served as executive vice president and chief financial officer of ConocoPhillips Company from October 2010 to February 2016. Mr. Sheets was associated with ConocoPhillips and its predecessor companies for more than 36 years and served in a variety of roles, including senior vice president of planning and strategy as well as vice president and treasurer. He began his career in 1980 as a process engineer with Phillips Petroleum Company. Mr. Sheets also serves on the board of directors of Westlake Chemical Corporation and is a former director of DCP Midstream Partners LP. Mr. Sheets received a bachelor's degree in chemical engineering from the Missouri University of Science and Technology and an MBA from the University of Houston. Mr. Sheets is a member of the Board of Trustees at the Missouri University of Science and Technology.

 

 

 

 

D. PRE‑APPROVAL POLICIES AND PROCEDURES

 

The Committee has implemented a policy restricting the services that may be provided by the Corporation's auditors and the fees paid to the Corporation's auditors. Prior to the engagement of the Corporation's auditors to perform both audit and non‑audit services, the Committee pre‑approves the provision of the services. In making their determination regarding non‑audit services, the Committee considers the compliance with the policy and the provision of non‑audit services in the context of avoiding impact on auditor independence. All audit and non‑audit fees paid to KPMG and Deloitte in 2018 and 2017 were pre‑approved by the Committee. Based on the Committee's discussions with management and the independent auditors, the Committee is of the view that the provision of the non‑audit services by KPMG and Deloitte described above is compatible with maintaining that firm's independence from the Corporation.

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     D-2

 

 

 

E. EXTERNAL AUDITOR SERVICE FEES

 

The aggregate fees paid by the Corporation to KPMG (after May 31, 2017) and Deloitte (before May 31, 2017), each an Independent Registered Public Accounting Firm, and the independent auditors of Enerplus at relevant times, for professional services rendered in Enerplus' last two fiscal years are as follows:

 

 

 

 

 

 

 

 

 

 

    

 

2018

    

 

2017

 

 

(in $ thousands)

Audit fees (1)

Deloitte

$

-

 

$

137.5

 

KPMG

$

662.0

 

$

605.0

Audit-related fees (2)

Deloitte

 

-

 

 

-

 

KPMG

 

-

 

 

-

Tax fees (3)

Deloitte

 

 

 

 

64.5

 

KPMG

 

43.1

 

 

61.3

All other fees (4)

Deloitte

 

-

 

 

-

 

KPMG

 

-

 

 

15.2

Total

Deloitte

$

-

 

$

202.0

 

KPMG

$

705.1

 

$

681.5

 

Notes:

(1)

Audit fees in 2018 were for professional services rendered by KPMG for the audit of the Corporation's annual financial statements and review of the Corporation's quarterly financial statements, as well as services provided in connection with statutory and regulatory filings or engagements.

(2)

Audit-related fees are for assurance and related services provided by KPMG reasonably related to the performance of the audit or review of the Corporation’s financial statements and not reported under “Audit fees” above.

(3)

Tax fees in 2018 were for tax compliance, tax advice and tax planning by KPMG.

(4)

All other fees in 2018 related to products and services provided by KPMG other than those described as "Audit fees "  and "Tax fees". For 2017, other fees include French translation services.

 

 

D-3      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

AUDIT & RISK MANAGEMENT COMMITTEE CHARTER

 

I.         AUTHORITY

 

The Audit & Risk Management Committee (the “Committee”) of the Board of Directors (the “Board”) of Enerplus Corporation (the “Corporation”) shall be comprised of three or more Directors as determined from time to time by resolution of the Board.  Consistent with the appointment of other Board committees, the members of the Committee shall be elected by the Board at the first meeting of the Board following each annual meeting of Shareholders of the Corporation or at such other time as may be determined by the Board. The Chair of the Committee shall be designated by the Board, provided that if the Board does not so designate a Chair, the members of the Committee, by majority vote, may designate a Chair.  The presence in person or by telephone of a majority of the Committee’s members shall constitute a quorum for any meeting of the Committee. All actions of the Committee will require the vote of a majority of its members present at a meeting of the Committee at which a quorum is present.

 

Members of the Committee do not receive any compensation from the Corporation other than compensation as directors and committee members. Prohibited compensation includes fees paid, directly or indirectly, for services as consultant or as legal or financial advisor, regardless of the amount, but excludes any compensation approved by the Board and that is paid to the directors as members of the Board and its committees.

 

II.         PURPOSE OF THE COMMITTEE

 

The Committee’s mandate is to assist the Board in fulfilling its oversight responsibilities with respect to:

 

1.          financial reporting and continuous disclosure of the Corporation

2.          the Corporation’s internal controls and policies, the certification process and compliance with regulatory requirements over financial matters

3.          evaluating and monitoring the performance and independence of the Corporation’s external auditors and

4.          monitoring the manner in which the business risks of the Corporation are being identified and managed

 

The Committee shall report to the Board on a regular basis with regard to such matters. The Committee has direct responsibility to recommend the appointment of the external auditors and approve their remuneration. The Committee may take such actions as it deems necessary to satisfy itself that the Corporation’s auditors are independent of management. It is the objective of the Committee to maintain free and open communication among the Board, the external auditors, and the financial senior management of the Corporation.

 

III.         COMPOSITION AND COMPETENCY OF THE COMMITTEE

 

Each member of the Committee shall be unrelated to the Corporation and, as such, shall be free from any relationship that may interfere with the exercise of his or her independent judgement as a member of the Committee.  All members of the Committee shall be financially literate and at least one member of the Committee shall have accounting or related financial management expertise – "literate” or “literacy” and “expertise” as defined by applicable securities legislation.  Members are encouraged to enhance their understanding of current issues through means of their preference.

 

IV.        MEETINGS OF THE COMMITTEE

 

The Committee shall meet with such frequency and at such intervals as it shall determine is necessary to carry out its duties and responsibilities. As part of its purpose to foster open communications, the Committee shall meet at least quarterly with management and the Corporation’s external auditors in separate executive sessions to discuss any matters that the Committee or each of these groups or persons believes should be discussed privately. The Chair works with the Chief Financial Officer and external auditors to establish the agendas for Committee meetings, ensuring that each party’s expectations are understood and addressed. The Committee, in its discretion, may ask members of management or others to attend its meetings (or portions thereof) and to provide pertinent information as necessary. The Committee shall maintain minutes of its meetings and records relating to those meetings and the Committee’s activities and provide copies of such minutes to the Board.

 

V.         DUTIES AND ACTIVITIES OF THE COMMITTEE

 

Evaluating and monitoring the performance and independence of external auditors

 

1.          Make recommendations to the Board on the appointment of external auditors of the Corporation

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     D-4

 

 

 

2.          Review and approve the Corporation’s external auditors’ annual engagement letter, including the proposed fees contained therein

 

3.          Review the performance of the external auditors and make recommendations to the Board regarding their replacement when circumstances warrant.  The review shall take into consideration the evaluation made by management of the external auditors’ performance and shall include:

 

a)          review annually the external auditors’ quality control, any material issues raised by the most recent quality control review, or peer review, of the firm, or any inquiry or investigation by governmental or professional authorities of the firm within the preceding five years, and any steps taken to deal with such issues

 

b)          obtain assurances from the external auditors that the audit was conducted in accordance with Canadian and U.S. generally accepted auditing standards and

 

c)          ensure that management interacts professionally with the auditors and confirm such behavior annually with both parties

 

4.          Oversee the independence of the external auditors by, among other things:

 

a)          requiring the external auditors to deliver to the Committee on a periodic basis a formal written statement detailing all relationships between the external auditors and the Corporation

 

b)          reviewing and approving the Corporation’s hiring policies regarding partners, employees and former partners and employees of current and former external auditors

 

c)          actively engaging in a dialogue with the external auditors with respect to any disclosed relationships or services that may impact the objectivity and independence of the external auditors and recommending that the Board take appropriate action to satisfy itself of the auditors’ independence    

 

d)          pre-approving the nature of non-audit related services and the fees thereon 

 

e)          conducting private sessions with the external auditors and encouraging direct communications between the Chair of the Committee and the audit partner 

 

f)           instructing the Corporation’s external auditors that they are ultimately accountable to the Committee and the Board and that the Committee and the Board are responsible for the selection (subject to Shareholder approval), evaluation and termination of the Corporation’s external auditors

 

g)          have a private meeting with the external auditors at every quarterly Committee meeting

 

h)          obtain annually the auditors’ views on competency and integrity of the Committee and senior financial executives

 

Oversight of annual and quarterly financial statements, management discussion and analysis and press releases

 

5.          Review and approve the annual audit plan of the external auditors, including the scope of audit activities, and monitor such plan’s progress and results quarterly and at year end

 

6.          Confirm, through private discussions with the external auditors and management, that no restrictions are being placed on the scope of the external auditors’ work

 

7.          Review the appropriateness of management’s representation letter transmitted to the external auditors

 

8.          Receipt of certifications from the CEO and CFO

 

9.          Review with management the adequacy of annual and quarterly financial statements and disclosure in the management discussion and analysis and press release and recommend approval to the Board of:

 

a)          satisfactory answers from management following the review of the annual and quarterly financial statements and management discussion and analysis and press release

 

D-5      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

b)          the qualitative judgments of the external auditors about the appropriateness, not just the acceptability, of accounting principles and financial disclosure practices used or proposed to be adopted by the Corporation and, particularly, their views about alternate accounting treatments and their effects on the financial results

 

c)          the methods used to account for significant unusual transactions

 

d)          the effect of significant accounting policies in controversial or emerging areas for which there is a lack of authoritative guidance or consensus

 

e)          management’s process for formulating sensitive accounting estimates and the reasonableness of these estimates

 

f)           significant recorded and unrecorded audit adjustments

 

g)          any material accounting issues among management and the external auditors

 

h)          other matters required to be communicated to the Committee by the external auditors under generally accepted auditing standards and

 

i)           management’s acknowledgement of its responsibility towards the financial statements

 

j)           significant legal, compliance or regulatory matters that may have a material effect on the financial statements or the business of the organization (including material notices to, or inquiries received from, governmental agencies) and

 

k)          receive the report from the Reserves Committee over the appropriateness of reported reserves and resources

 

Oversight of financial reporting process, internal controls, the continuous disclosure and certification process and compliance with regulatory requirements

 

10.        Establishment of the Corporation’s Whistleblower Policy for the submission, receipt, retention and treatment of complaints and concerns regarding accounting and auditing matters, and review any developments and responses on reports received thereunder

 

11.        Review the adequacy and effectiveness of the financial reporting system and internal control policies and procedures with the external auditors and management.  Ensure that the Corporation complies with all new regulations in this regard

 

12.        Review with management the Corporation’s internal controls, and evaluate whether the Corporation is operating in accordance with prescribed policies and procedures

 

13.        Review with management and the external auditors any reportable condition and material weaknesses affecting internal controls

 

14.        Review the management disclosure and oversight Committee’s CEO and CFO certification processes to ensure compliance with US and Canadian requirements

 

15.        Receive periodic reports from the external auditors and management to assess the impact of significant accounting or financial reporting developments proposed by the CICA, the AICPA, the Financial Accounting Standards Board, the SEC, the relevant Canadian securities commissions, stock exchanges or other regulatory body, or any other significant accounting or financial reporting related matters that may have a bearing on the Corporation and

 

16.        Review annually the report of the external auditors on the Corporation’s internal controls over financial reporting describing any material issues raised by the most recent reviews of internal controls and management information systems or by any inquiry or investigation by governmental or professional authorities and any recommendations made and steps taken to deal with any such issues

 

Review of Business Risks

 

17.        Review with management the process followed to do the Corporation’s key risk assessment and review the policies to monitor, mitigate and report such business risks and ESG risks.

 

ENERPLUS 2018 ANNUAL INFORMATION FORM     D-6

 

 

 

Other Matters

 

18.        Review of appointment or dismissal of senior financial executives

 

19.        Conduct or authorize investigations into any matters within the Committee’s scope of responsibilities, including retaining outside counsel or other consultants or experts for this purpose

 

20.        Review the disclosure made in the Annual Information Form, 40-F and the Information Circular regarding the Committee 

 

21.        Establish and maintain a free and open means of communication between the Board, the Committee, the external auditors, and management

 

22.        Perform such additional activities, and consider such other matters, within the scope of its responsibilities, as the Committee or the Board deems necessary or appropriate and

 

23.        Once a year, review the adequacy of its Charter and bring to the attention of the Board required changes, if any, for approval.  The Committee is also reviewed annually by the Corporate Governance and Nominating Committee, which reports its findings to the Board

 

24.        Hold an in-camera session of the independent members of the Committee at each meeting of the Committee

 

While the Committee has the duties and responsibilities set forth in this Charter, the Committee is not responsible for planning or conducting the audit or for determining whether the Corporation’s financial statements are complete and accurate and are in accordance with generally accepted accounting principles.  Similarly, it is not the responsibility of the Committee to resolve disagreements, if any, between management and the external auditors.  While it is acknowledged that the Committee is not legally obliged to ensure that the Corporation complies with all laws and regulations, the spirit and intent of this Charter is that the Committee shall take reasonable steps to encourage the Corporation to act in full compliance therewith.

 

 

 

D-7      ENERPLUS 2018 ANNUAL INFORMATION FORM

 

 

 

PICTURE 5

 

Enerplus Corporation

 

The Dome Tower
3000, 333 ‑ 7th Avenue S.W.
Calgary, Alberta, Canada
T2P 2Z1
Telephone: 403.298.2200
Toll free: 1.800.319.6462
Fax: 403.298.2211
www.enerplus.com

 

 

 

 

EXHIBIT 99.10

 

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES‑OXLEY ACT OF 2002

 

 

In connection with the annual report of Enerplus Corporation (the “Corporation”) on Form 40‑F for the fiscal year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jodine J. Jenson Labrie, Senior Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

 


Senior Vice President and
Chief Financial Officer of Enerplus Corporation

 

 

/s/ Jodine J. Jenson Labrie

 

Jodine J. Jenson Labrie
Senior Vice President and
Chief Financial Officer of Enerplus Corporation

 

February 22, 2019

The foregoing certification shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of that section. Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the registrant specifically incorporates it by reference.

EXHIBIT 99.11

CODE OF BUSINESS CONDUCT

The Code of Business Conduct is our guide to ethical and lawful conduct in our daily business. It requires all of us, from members of our board of directors to new hires, to adhere to a level of ethical business conduct well in excess of the legal minimum. Our compliance with both the letter and spirit of the Code of Business Conduct is essential to protecting Enerplus’ business and reputation.

INTRODUCTION

Enerplus’ Commitment

Enerplus Corporation and all of its affiliates (“Enerplus” or the “Corporation”) are committed to maintaining the highest of business standards in our operations, wherever they may be. We recognize the importance of credibility, integrity, and trust to our success as a business.

Purpose and Applicability of the Code

This Code of Business Conduct summarizes a number of Enerplus policies for appropriate behaviour and applies to all employees, consultants, officers and directors of Enerplus (hereinafter, “Employees”). Accordingly, each of us must comply with the terms of this Code. The Code will help us meet our business practice standards and comply with applicable laws and regulations. It is essential that this Code of Business Conduct be observed. The Code is very important to protecting Enerplus’ business and reputation .

 

The Code of Business Conduct is a general guideline for making certain that:

·

A work environment is maintained that promotes the dignity and self-respect of each Employee.

·

All Employees are aware of and fully observe the laws and regulations that impact their business activities.

·

A standard of behaviour is in place that reflects the values and integrity of Enerplus and its Employees.

·

Enerplus is protected from financial loss and legal liability.

This Code of Business Conduct does not replace any other published rules and policies of Enerplus, including other guidelines and personal conduct policies. All Enerplus policies and standards are subject to this Code. While this Code of Business Conduct provides guidance and explains what is considered unacceptable behaviour, the Code of Business Conduct does not describe every specific act that is unacceptable. If a specific act is missing from the Code, it does not mean that act is acceptable or condoned. Ultimately, we must rely on our judgment about the right thing to do in order to maintain our personal and corporate integrity.

The Code is to be used as a guide for appropriate conduct and to prevent improper conduct. Enerplus will not tolerate any conduct that is unlawful or damaging to Enerplus’ reputation.

Employee Responsibilities

All Employees are responsible for reading this entire Code of Business Conduct and ensuring their conduct is consistent with both the letter and the spirit of Enerplus’ business practices .

This Code will help Employees deal with specific situations. In some cases, a situation may be so complex or circumstances so unique that additional guidance is needed. If such a situation occurs and is not included in this Code, it is each Employee’s duty to contact his/her supervisor or the People and Culture Department immediately. If necessary, the People and Culture Department may refer the matter to the Legal Department for further advice.

 

This Code and any detailed Enerplus policy statements and procedures will be updated from time to time. All Employees are required to stay informed of any updates and to comply with all requirements .

Management Responsibilities

Managers must exhibit the highest standards of corporate responsibility and business conduct and create a work atmosphere that supports our corporate values and policies, including this Code. It is the duty of each member of management to take into account an Employee’s willingness and commitment to comply with this Code when making promotion and other employment decisions .

Compliance Requirements

Employees must work honestly and in good faith. Employment with Enerplus depends upon an Employee’s ability and willingness to comply with this Code. Adherence to these standards carries the highest priority. All Employees are required to acknowledge compliance when they are hired and again on an annual basis.

GLOBAL BUSINESS CONDUCT GUIDELINES

Our Employees

Discrimination, Bullying and Workplace Harassment

Employees are forbidden to discriminate against, bully or harass other Employees, in keeping with our Harassment Policy. No Employee is permitted to act in a way that is considered or could be considered illegal or harassing .

It is the responsibility of each member of management to be diligent in recognizing and responding to any behaviour or conduct that could be considered workplace harassment, bullying or discrimination. Management also is required to apply our policies and immediately contact the People and Culture Department regarding any situation that could be considered workplace harassment, bullying or discrimination.  

It is the responsibility of each Employee to maintain a work environment free of discrimination, bullying and harassment and to report any situation that the Employee believes may be workplace harassment, bullying or discrimination to his/her supervisor, department head or the People and Culture Department .

Employment of Family Members

Enerplus allows an Employee’s spouse, parents, children, and other family members to work for Enerplus, both during and after the employee’s career with Enerplus, provided the employment is in Enerplus’ best interest. Family relationships, however, will not be considered in hiring decisions. All Enerplus hiring decisions will be made strictly on the basis of individual qualifications. To avoid the possibility or appearance of preferential treatment, Enerplus will not have one family member placed in a position of influence over another family member .

Workplace Health and Safety

The health and safety of our personnel and the safe operation of our facilities are principal objectives of Enerplus. We are committed to providing safe and healthy places of employment and will follow operating practices that eliminate or minimize exposure to hazardous or unhealthy conditions. The success of our health and safety efforts depends upon the cooperation, support, and active involvement of all Enerplus personnel. Each Employee is responsible for working safely and complying with all safety rules and protocols at all times. We are committed to maintaining a safe and secure work environment. Threats, intimidation, harassment, assaults, and acts of violence are unacceptable and will not be tolerated .  

Employees should refer to the Safety & Social Responsibility section of the Enerplus website for our Safety & Social Responsibility Policy and minimum safety standards. Questions or concerns should be reported immediately to a supervisor, the Safety & Social Responsibility Department or the People and Culture Department .

 

 

Prohibited Items

The use, sale, possession or distribution of illegal drugs, or the improper use of alcohol or prescription drugs, by Employees is strictly forbidden while on Enerplus premises, in Enerplus vehicles, or while conducting Enerplus business on or off Enerplus premises. The use of alcohol is prohibited to the extent that it has a detrimental effect on job performance, safety, or efficiency while conducting Enerplus business on or off Enerplus premises. The approval of an Enerplus officer is required to consume or possess alcoholic beverages on Enerplus premises. Consumption of alcohol in Enerplus owned or leased vehicles or personal vehicles used for Enerplus business is strictly prohibited, and possession is permitted only in accordance with the Alcohol and Drug Policy. For further information, please refer to the Alcohol and Drug Policy . 

The possession, use, or distribution of firearms, weapons, and explosives is prohibited while on Enerplus premises, while conducting Enerplus business, or while in Enerplus vehicles on or off Enerplus premises, except as authorized under the Firearm Storage, Transportation and Use Standard found on the Safety & Social Responsibility section of the Enerplus website .

If evidence supports a reasonable suspicion of use, possession, or distribution of prohibited items, Enerplus reserves the right to conduct searches on Enerplus premises or in Enerplus owned or leased vehicles for such items .  

Our Company

Document Retention

Employees must comply with Enerplus’ department-specific document (physical and electronic) retention guidelines to ensure that all applicable laws and regulations are met. Each Employee should become familiar with and adhere to these guidelines. Additionally, when litigation or an investigation is pending, Employees are prohibited from modifying or destroying relevant documents or records, including Employees’ personal files and electronic records. The consequences of modifying or destroying any relevant documents or records are severe and may include prosecution. An Employee who has any doubt about the legality or propriety of modifying or destroying any document or record should contact his/her supervisor or General Counsel before proceeding .

External Communications

From time to time, Employees may be contacted by government representatives or legal counsel representing other companies, government agencies, or individuals in connection with investigations that concern Enerplus, its business, counterparties, Employees, or suppliers. While Enerplus cooperates with all reasonable requests from government agencies and authorities related to Enerplus’ business, an Employee receiving a request for information other than what is provided on a routine basis should decline to respond and immediately report the request to his/her supervisor and seek guidance from the Legal Department. Likewise, if an Employee receives a subpoena or other request to testify or produce documents in relation to Enerplus’ business, a copy of the subpoena or request should be forwarded immediately to our General Counsel. All information provided should be truthful and accurate. Employees must never mislead any investigator and must never modify or destroy documents or records in response to an investigation .

 

Disclosure of Corporate Information; Trading Restrictions

Employees must not trade Enerplus securities while in possession of material, non-public corporate information. Employees must not use such material, non-public corporate information for their benefit or the benefit of others. Material corporate information is any information that, if known, might influence a reasonable investor’s investment decision to buy, sell, or hold securities of Enerplus. Non-public means any corporate information that has not been released by Enerplus for public dissemination and which is intended to remain confidential until such authorized dissemination. With the exception of disclosure to Enerplus’ advisors, Employees should not share material, non-public corporate information with anyone outside Enerplus (including family members) until it has been made public, regardless of how the information may or may not be used. These restrictions also apply to trading in securities of any other company (including, but not limited to, competitors, suppliers, and counterparties) if an Employee learns of any material, non-public information about that company during the course of his/her employment with Enerplus .  

Employees must adhere to blackout restrictions posted on published blackout calendars. Trading blackouts are implemented to ensure that “insiders” do not have the advantage of information that has not been announced to the general investing public. “Insiders” are considered to be anyone who has access to information that has not been released to the public realm. Applicable securities laws dictate the protection of the entire investing public to ensure fairness. Should an individual breach insider trading rules they may be subject to significant penalties by regulatory authorities .

Announcements of material information will include scheduled and unscheduled announcements. Scheduled announcements include the release of quarterly financial statements, annual financial statements and annual reports of Enerplus, and in that regard, trading in Enerplus securities by Employees will be prohibited for a certain time before and after the release of financial statements. Unscheduled announcements may include the release of information relative to changes in the Corporation of a financial or structural nature, which may or may not require trading blackouts .

Management will make every attempt to inform Employees of changes to blackout periods. However, blackout periods may change without notice. Should you have any questions or require clarification regarding trading restrictions, it is your responsibility to direct these questions to General Counsel prior to trading any Enerplus securities .

Employees must report violations or misuse of material, non-public corporate information to our General Counsel immediately .

Directors and officers of Enerplus are required by securities regulations to make certain filings with securities commissions to report their holdings and transactions in Enerplus’ securities. Questions about these laws should be directed to the General Counsel .

Directors and other Employees of Enerplus may not, directly or indirectly, buy, sell or enter into :

• any short sale of securities of Enerplus;

• any puts, call options or other rights or obligations to buy or sell securities of Enerplus;

• any derivative instruments, agreements or securities, the market price, value or payment obligations of which are derived from or based on the value of securities of Enerplus; or

• any other derivative instruments, agreements, arrangements or understandings (commonly known as equity monetization transactions), the effect of which is to alter, directly or indirectly, a director’s or other Employee’s economic interest in securities of Enerplus, with the exception of corporate equity hedges or normal course issuer bids .

Enerplus believes that the interests of the Corporation’s directors, officers and other Employees should be aligned with those of the Corporation’s other shareholders. Engaging in the above activity frustrates our intention that directors and officers hold a meaningful ownership interest in Enerplus and bear the full risks and rewards of ownership .

 

 

 

Conflicts of Interest

Employees are not permitted to do anything that does not support the best interests of Enerplus. For example :  

·

An Employee should not use Enerplus property for his/her own material benefit.

·

An Employee should not influence Enerplus’ contractors or consultants for his/her own personal gain.

·

An Employee, or his/her family members or friends, should not act on business opportunities or investments presented to Enerplus, other than for the benefit of the Corporation, that are not available to the public, without written permission from General Counsel.

·

An Employee should not make or recommend decisions for Enerplus that might benefit the Employee, his/her family members, or friends financially.

·

An Employee or their spouse should not own a five percent (5%) or more equity interest in any entity that sells supplies, furnishes services, or otherwise does business with Enerplus without written permission from General Counsel.

·

An Employee or their spouse should not own a five percent (5%) or more equity interest in any entity that is a competitor of Enerplus without disclosing such interest.

Before acknowledging compliance with this Code, an Employee must report in writing any conflicts of interest to the People and Culture Department. If conflicts of interest arise after the Employee has acknowledged compliance, the Employee must report the conflicts immediately in writing to the People and Culture Department, which will disclose such conflicts to General Counsel .

During regular business hours, Employees should devote their full time and attention to Enerplus and their assigned job duties unless they have received permission from their leader. Unrelated outside activities, business, or secondary employment are not permitted during regular business hours except as provided above .

With the exception of Enerplus directors, no Employee of Enerplus should serve on the executive or board of any corporation that Enerplus does not control or have an ownership interest in without the written approval of Enerplus’ General Counsel. It is acceptable to serve on the board of a non-profit, charitable, religious, or civic organization without prior written approval, provided it does not interfere with or impair the Employee’s ability to perform their duties at Enerplus and represents a commitment of personal time .  

To avoid potential conflicts of interest, it is against Enerplus’ policy for Enerplus to extend loans to officers or directors . 

Confidential and Proprietary Information

Occasionally, Employees may know confidential information concerning Enerplus’ business, including counterparties, suppliers, business contacts, Employees, or technical operations. Employees must keep this information confidential during and after their employment with Enerplus. Personal information relating to Enerplus counterparties, suppliers, business contacts or Employees must be treated in accordance with Enerplus' Privacy Policy .

Generally, any information stored by and/or processed by Enerplus is proprietary information. This confidential information includes computerized data, methods, techniques, and documentation relating to Enerplus’ computing services, developed software, and third-party software .

Employees must be aware of their responsibilities regarding access to Enerplus’ computer services, and the access, use, and disclosure of confidential information. Confidential and proprietary information must be used for Enerplus purposes only, never for personal gain. Enerplus prohibits Employees from releasing or misusing any confidential and proprietary Enerplus information .  

 

Accounting and Reporting

Accurate documents are important during audits and other internal or external reviews. All Employees must comply with Enerplus’ accounting and reporting procedures and make sure all books, records, accounts, and supporting papers are accurate and complete. Employees are forbidden to forge, falsify, or intentionally leave out important facts on any business documents of Enerplus which could mislead auditors or other internal or external reviewers .

Expense Accounts

Employee expense accounts are to be used only to reimburse Employees for items and activities that are purchased for Enerplus business. Employees must submit accurate expense reports of the money spent for this purpose. Where expenses are incurred in the presence of other Employees, the Employee with the most seniority should make the payment .

Enerplus’ Information Technology Resources

Corporate information, information systems and electronic communications are considered assets and valuable resources to Enerplus. Enerplus requires the appropriate use of these assets and their protection in a manner commensurate with their sensitivity, value and criticality. Any electronic communication of personal information must be in accordance with Enerplus’ Privacy Policy .

All Employees are required to:

·

Manage and protect corporate information, information systems and electronic communications in accordance with all Enerplus policies, standards and procedures, including statutory and regulatory requirements;

·

Take accountability for appropriate security, access and retention of specific information they are responsible for; and

·

Report incidents and assist in investigations relating to the misuse of information assets.

Enerplus’ information technology resources, such as email and internet access, are provided to Employees in pursuit of Enerplus’ business. While limited personal use of these resources is acceptable, Employees should not expect their use of these resources to be private or confidential. Personal use of these resources, such as accessing social networking/media websites (e.g. Facebook, Instagram, Twitter, YouTube, etc.), also should not interfere with Employee productivity or business processes .

Employees should take the same care in their electronic communications as they take when they communicate in person or by paper. Information and data are at risk when transmitted over the internet .

Employees shall not use Enerplus’ information technology resources inappropriately, including the following prohibited activities :

 

·

Accessing, viewing, downloading , storing or redistributing any material or message that is illegal or offensive

·

Activities designed to evade, compromise or otherwise exploit security controls

·

Possession or use of assessment and discovery tools that could be used to collect information to compromise the security of Enerplus’ information system or launch attacks against other parties’ information systems;

·

The intentional creation and/or transmission of malicious code (viruses, worms, etc.);

·

Malicious activity including, but not limited to: erasing, renaming or making unusable any software, data or information;

 

·

Disclosing , gathering or using another Employee’s account/password to access any information technology resources;

·

Participation in chain letters or other forms of mass mailing or marketing; or

·

Connecting non- Enerplus /personal devices (laptops, external hard/flash drives, etc.) directly to an Enerplus device or network unless authorized by the Information Services Department.

Enerplus does not allow Employees to copy or distribute copyrighted materials (e.g., software, database files, articles, graphics, music, movies, etc.) through Enerplus’ email system or by any other means without confirming in advance from appropriate sources that Enerplus has the right to copy or distribute the material. Employees are not permitted to install any software on Enerplus’ information systems without the express written consent of an executive with responsibility for the Information Services Department .

An Employee’s logon IDs and passwords are intended for his/her use only and each Employee is responsible for all activity that occurs under their accounts. Employees must protect their accounts through the use of strong passwords .

Enerplus may access its information technology resources at any time as part of an internal audit or to investigate suspected unauthorized use, and may disclose the information it accesses to law enforcement or other third parties without prior consent of the sender or the recipient .

Employees should consult the Information Assets Security Policy and the Information Services Security section of the Enerplus website for further information regarding security standards, guidelines and awareness .

Internet/Intranet Site Development

Enerplus’ internet and intranet are important platforms to communicate Enerplus information to Employees, counterparties, and the public .

As such, the Corporation’s Information Services Department and the People and Culture Department shall be solely responsible for and shall administer the creation and development of all Enerplus internet and intranet sites. From time to time and based on business need, access to internet or intranet pages may be granted to Employees for creation or revision of content. Employee and stakeholder suggestions for enhancement to the sites are encouraged .

Corporate Logo

The logos of Enerplus and its business units are considered property of Enerplus and must only be used for business purposes. Only the approved logos, which are available through the People and Culture Department and the intranet, may be used, and approval must be obtained prior to using any Enerplus logo on materials to be distributed outside of Enerplus. Re-creation or alteration of Enerplus’ logos is not permitted. Acquisition of all logo items, such as apparel and office items, must be coordinated through the Stakeholder Engagement, Safety & Social Responsibility or Investor Relations teams .

Our Business Partners and Counterparties

Relationships with Contractors and Suppliers

Contractor and supplier relationships must be managed in a fair, equitable, and ethical manner consistent with this Code of Business Conduct, all applicable laws, and good business practices .

Enerplus promotes competitive procurement to the maximum extent practical and evaluates every supplier’s products and services on the basis of technical excellence, quality, reliability, service, price, delivery, and other relevant objective factors. Enerplus prohibits Employees from making purchasing decisions on the basis of personal relationships, friendships, or the opportunity for personal financial gain .

 

Employees must respect the terms of supplier and contractor contracts and licensing agreements and safeguard all confidential information received from a contractor or supplier, including pricing, technology, or proprietary design information. This confidential information must not be disclosed to anyone outside Enerplus without the written permission of the supplier or contractor .

All contractors who exchange or receive personal information from Enerplus must have privacy policies and practices in compliance with applicable Canadian and United States federal, provincial and state laws .

Anti-Corruption

Enerplus is committed to honesty and integrity in all of its business operations and will actively avoid corruption. We recognize that we may operate in jurisdictions which have different standards of ethical behaviour. Regardless of location, Employees shall carry out their duties in accordance with the principles set out in this Code and, specifically, will comply with all applicable anti-bribery and fair practices legislation. 

Acts of corruption, either direct or indirect, are prohibited. Accordingly, Employees shall not engage in any acts that are improper or could appear to be improper, including the following:

 

·

Paying bribes or kickbacks to, or accepting bribes or kickbacks from, public officials or private individuals;

·

Making facilitation payments;

·

Failing to keep complete and accurate records of transactions;

·

Approving payment of invoices or expenses without proper back-up or scrutiny;

·

Engaging in joint ventures or retaining agents or consultants to deal with public officials without conducting adequate due diligence of the counterparty’s previous activities or reputation.

 

Compliance with these principles will ensure that Enerplus’ business activities are transparent and our commercial relationships are based upon honesty and fairness.

Gifts and Entertainment

Reasonable gifts and entertainment are a part of normal business courtesy and are not prohibited. In many cultures, exchanging gifts or entertainment is designed to foster trust in a business relationship. However, Employees should always use good judgment and discretion to avoid the appearance of impropriety or obligation. Enerplus Employees should be certain that any gifts given or received, or entertainment hosted or attended as a guest, do not violate the law, customary business practices, or this Code of Business Conduct .

While Employees may exchange or accept gifts with their counterparties and suppliers as part of normal business courtesy, no gift, favour, or payment should be accepted which imparts a future obligation on the Employee or was given in an attempt to influence decisions regarding the business of Enerplus. Additionally, the value of the gifts exchanged should be reasonable, and the exchanges should occur infrequently .

Likewise, while Employees may be participants in entertainment with their counterparties and suppliers as hosts or guests in the normal course of a business relationship, Employees must not be participants when the entertainment is an attempt to influence decisions regarding the business of Enerplus or imparts a future obligation on the Employee. Additionally, the value of the entertainment should be reasonable and the Employee’s participation should occur infrequently. Finally, Employees are prohibited from participating in inappropriate entertainment as either a guest or a host .  

Gifts and entertainment in excess of $300 may be accepted, if approved in advance by an executive officer. Executive officers may accept such gifts and entertainment with prior approval from their leader or the chairman of the board of directors. If a gift has been received but, given the circumstances, the gift is determined to be inappropriate, your manager may require the gift to be returned to the originator. An Employee who has any doubt about the propriety of a gift or entertainment should contact his/her supervisor or the People and Culture Department before accepting the gift or participating in the proposed activity .

 

Obtaining and Using Competitor Information

While information about our competitors, counterparties, and suppliers is a valuable asset, the law and our standards of appropriate business conduct require that our Employees obtain this information legally. It is not unusual to obtain information about other organizations, including our competitors, through legal and ethical means such as public documents, public presentations, journal and magazine articles, and other published and spoken information. However, Employees are prohibited from obtaining proprietary or confidential information about our competitors, counterparties, or suppliers through illegal means, or from using any proprietary or confidential information acquired during a prior   employment relationship. It is also not acceptable to use or seek to acquire proprietary or confidential information when doing so would require anyone to violate a contractual arrangement, such as a confidentiality agreement with a prior employer. Employees are prohibited from taking any improper actions to gain information about our competitors, counterparties, and suppliers .

Our Communities

Environmental Compliance

Enerplus is dedicated to complying with all relevant environmental laws and regulations and requires Employees to comply with these laws and regulations as well. It is the duty of each Employee to report what he/she believes to be environmental violations to his/her supervisor or the Safety & Social Responsibility Department. For further information, please refer to the Safety & Social Responsibility Policy .

Political Contributions

Only Enerplus’ President and CEO may authorize use of the Corporation’s resources to support political activities. Employees must not use Enerplus’ money, credit, property, or services for political activities. Outside of Enerplus business hours, Employees may participate in any political activities of their choice, but Enerplus will not support or reimburse Employees financially .

Requests for Information from the Media and Public

Enerplus’ President and CEO, Senior Vice-Presidents, Vice-Presidents of Operations and the Investor Relations Department are authorized to work with the media directly, and may designate other Employees to serve as spokespersons for the Corporation in specific circumstances (e.g., emergency management). When Enerplus provides information to the news media, Enerplus has the obligation to report accurately and completely all related material facts. In order to ensure that Enerplus complies with its obligations, Employees who are contacted by the media for information regarding Enerplus’ business activities and plans, financial information, or Enerplus’ position on public issues, must refer the request to the Investor Relations Department. Likewise, all requests from the media for interviews must be directed to Investor Relations. Employees may not answer any questions from any member of the media unless they have participated in Enerplus’ media training program and been designated as spokespersons .

Press Releases

Press releases allow Enerplus to announce important and relevant information to the public through the media. If a business unit or department within Enerplus anticipates the necessity for a press release to be created, the business unit or department must contact the Investor Relations Department to discuss the appropriateness of such a release and to provide the needed information. All press releases must be issued by the Investor Relations Department .

Public Speaking and Publishing Articles

Speeches and articles offer excellent opportunities for Enerplus and its Employees to present topics, ideas, and information of interest to business and professional audiences. These communications provide the public with a clearer understanding of Enerplus and its various business units. A speech or article on a professional topic written by an Employee for delivery to an audience or publication represents Enerplus. Speeches and articles must be approved by the Investor Relations Department prior to the speaking engagement or submission for publication. The Communications group may assist as well .

 

Social Networking and Blogs

Employees have the right to create personal blogs and postings on social networking websites. However, online misconduct can be grounds for discipline, even if it does not occur during business hours or using Enerplus’ resources. Inappropriate content for online employee postings includes, but is not limited to, the following :

 

·

Enerplus’ confidential or proprietary information ;

·

Information concerning Enerplus or Employees that would violate this Code or any other Enerplus policies, including the Privacy Policy; and

 

·

Negative comments about Enerplus or Employees, or that would harm the reputation of Enerplus or its Employees.

Employees should consult the Social Media Guidelines posted on the intranet for further information .

Community Involvement

Enerplus directly and through its Employees contributes to the general well-being and improvement of towns, cities, and regions where it has operations. Enerplus provides support to worthwhile community programs in areas such as social welfare, health, education, and arts and culture to promote the development of positive relationships in the areas where we have business interests. Enerplus also encourages the recruitment of qualified local personnel where practical. All Enerplus community involvement activities and requests for corporate contributions must be approved by the Communications group in coordination with the Stakeholder Engagement team .

While Enerplus encourages Employees to participate in charitable organizations and other community activities of their choice, these outside activities should not interfere with job duties. Accordingly, prior approval from your manager must be obtained when participation is supported by Enerplus and when utilizing Enerplus resources (including work time, e.g. days of caring). Where participation is on personal time and does not conflict with job duties then approval is not required. No Employee may pressure another Employee to express a view that is contrary to a personal belief or to contribute to or support political, religious, or charitable causes .

Community Projects

When a new project or business issue affects a local community, the business unit should seek the guidance of the Stakeholder Engagement team and the Communications group to help facilitate communications with the affected community. These groups will serve as support, proactively building and maintaining relationships with local communities as project development occurs. This will include developing a consistent platform to help educate landowners and communities on Enerplus’ operations and safety programs .

Reporting Violations and Resources for Guidance

This Code and other Enerplus policies provide general information for seeking guidance or reporting violations of the Code to supervisors, department heads, the People and Culture Department or our General Counsel. For more serious breaches of this Code, or if you have not received a satisfactory response, please refer to the Whistleblower Policy discussed below .

Whistleblower Policy

Enerplus has instituted a Whistleblower Policy to provide for the reporting and review of concerns relating to accounting and auditing matters, as well as other corporate misconduct and breaches of this Code of Business Conduct. Like the Code of Business Conduct, the Whistleblower Policy is designed to encourage ethical behaviour by all Enerplus Employees. Further details, and procedures for submitting a report, are set out in the  Whistleblower Policy .

 

 

Disciplinary Action

This Code is intended to help Employees conduct themselves in a manner consistent with our values. Employees may face disciplinary action if they :

·

Violate this Code

·

Encourage or help other Employees to violate this Code

·

Condone other Employees who violate this Code

·

Fail to report a Code violation

·

Conceal a Code violation

·

Retaliate against any Employee who reports a Code violation in good faith

·

Fail as an officer, director, manager, or supervisor to take appropriate steps to ensure compliance with this Code

Disciplinary action may include one or more of the following:

·

A warning

·

A written reprimand

·

Mandatory reimbursement of losses or damages

·

Suspension

·

Demotion

·

Termination of employment with Enerplus

·

Referral for criminal prosecution or civil action

Management has the discretion to determine the level and type of discipline that is appropriate in any given circumstance. For more information, please refer to the Progressive Discipline Procedure .

Clawback Policy

In addition to other possible disciplinary action, in cases of fraud or other intentional illegal conduct which affects Enerplus and its business, Employees may be subject to a clawback of their incentive compensation related to such activity. For further information, please refer to the Clawback Policy .

Monitoring

Enerplus will monitor compliance with its policies and procedures, including this Code .

 

 

 

Questions/Effect of this Code of Business Conduct

This Code is not a comprehensive listing of every Enerplus policy or applicable law. If questions arise about what this Code means or how it should be applied, Employees should contact their supervisor, department head or the People and Culture Department .


Sources of Information

 

 

Manager, People & Culture

(403) 298-2277

Manager, Safety & Social Responsibility

(403) 298-8940

VP, General Counsel & Corporate Secretary

(403) 298-4413

 

EXHIBIT 99.12

Supplemental Information About Oil and Gas Producing Activities (unaudited)

The following disclosures, including proved reserves, future net cash flows, and costs incurred attributable to Enerplus' crude oil and natural gas operations have been prepared in accordance with the provisions of the Financial Accounting Standards Board's Accounting Standards codification (ASC) Topic 932 "Extractive Activities – Oil and Gas”. The standard requires the use of a 12 month average price to estimate proved reserves calculated as the unweighted arithmetic average of first-day-of-the-month prices within the 12 month period prior to the end of the reporting period. Proved reserves and production volumes are presented net of royalties in accordance with U.S. protocol.

A. PROVED OIL AND NATURAL GAS RESERVE QUANTITIES

Users of this information should be aware that the process of estimating quantities of "proved developed" and "proved undeveloped" crude oil, natural gas and natural gas liquids is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Future fluctuations in prices and costs, production rates, or changes in political or regulatory environments could cause the Corporation's reserves to be materially different from that presented.

Proved reserves, proved developed reserves and proved undeveloped reserves are defined under the ASC. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulation. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The proved reserves disclosed herein are determined according to the definition of "proved reserves" under NI 51-101 which may differ from the definition provided in SEC rules, however the differences are not material to Enerplus’ proved reserves. The reserves data presented in this Exhibit are a summary of evaluations, and as a result the tables may contain slightly different numbers than the evaluations themselves due to rounding. Additionally, the columns and rows in the tables may not add due to rounding. See " Presentation of Enerplus' Oil and Gas Reserves, Contingent Resources, and Production Information " in Enerplus' Annual Information Form. All cost information in this section is stated in Canadian dollars and is calculated in accordance with accounting principles generally accepted in the United States of America (" U.S. GAAP ").

Subsequent to December 31, 2018, no major discovery or other favourable or adverse event is believed to have caused a material change in the estimates of proved reserves as of that date.

Enerplus’ December 31, 2018 proved crude oil, natural gas and natural gas liquids reserves are located in the United States, primarily in the states of Colorado, Montana, North Dakota, and Pennsylvania, as well as western Canada, primarily in Alberta, British Columbia, and Saskatchewan. Enerplus’ net proved reserves summarized in the following chart represent the Corporation’s lessor royalty, overriding royalty, and working interest share of reserves, after deduction of any Crown, freehold and overriding royalties:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

United States

 

Total

 

Total

 

 

Oil and

 

Natural

 

Oil and

 

Natural

 

Oil and

 

Natural

 

All

 

 

NGLs

 

Gas

 

NGLs

 

Gas

 

NGLs

 

Gas

 

Products

 

    

(Mbbls)

    

(MMcf)

     

(Mbbls)

    

(MMcf)

    

(Mbbls)

    

(MMcf)

    

(Mboe)

Proved Developed and Undeveloped

 

  

 

  

 

  

 

  

 

  

 

  

 

  

Reserves at December 31, 2015

 

35,072

 

103,232

 

53,702

 

298,392

 

88,774

 

401,624

 

155,711

Purchases of reserves in place

 

1,434

 

12,228

 

 —

 

 —

 

1,434

 

12,228

 

3,472

Sales of reserves in place

 

(2,954)

 

(49,069)

 

(4,204)

 

(2,998)

 

(7,158)

 

(52,067)

 

(15,836)

Discoveries and extensions

 

83

 

 —

 

12,515

 

28,288

 

12,598

 

28,288

 

17,313

Revisions of previous estimates

 

(234)

 

9,556

 

(7,722)

 

100,812

 

(7,956)

 

110,368

 

10,439

Improved recovery

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Production

 

(4,391)

 

(26,526)

 

(8,465)

 

(64,588)

 

(12,856)

 

(91,114)

 

(28,042)

Proved Developed and Undeveloped

 

  

 

  

 

  

 

  

 

  

 

  

 

  

Reserves at December 31, 2016

 

29,009

 

49,421

 

45,826

 

359,906

 

74,835

 

409,327

 

143,056

Purchases of reserves in place

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Sales of reserves in place

 

(2,412)

 

(10,332)

 

(111)

 

(86)

 

(2,523)

 

(10,418)

 

(4,260)

Discoveries and extensions

 

1,373

 

450

 

34,213

 

51,369

 

35,586

 

51,819

 

44,223

Revisions of previous estimates

 

2,841

 

12,247

 

2,771

 

124,796

 

5,612

 

137,043

 

28,453

Improved recovery

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Production

 

(3,428)

 

(15,235)

 

(8,429)

 

(63,526)

 

(11,857)

 

(78,761)

 

(24,984)

Proved Developed and Undeveloped

 

  

 

  

 

  

 

  

 

  

 

  

 

  

Reserves at December 31, 2017

 

27,383

 

36,551

 

74,270

 

472,459

 

101,653

 

509,010

 

186,488

Purchases of reserves in place

 

 —

 

 —

 

128

 

73

 

128

 

73

 

140

Sales of reserves in place

 

(40)

 

(4,252)

 

(136)

 

(64)

 

(176)

 

(4,316)

 

(895)

Discoveries and extensions

 

965

 

1,180

 

24,791

 

64,451

 

25,756

 

65,631

 

36,695

Revisions of previous estimates

 

269

 

930

 

4,020

 

189,251

 

4,289

 

190,182

 

35,986

Improved recovery

 

541

 

17

 

 —

 

 —

 

541

 

17

 

544

Production

 

(2,988)

 

(9,083)

 

(11,577)

 

(67,901)

 

(14,565)

 

(76,984)

 

(27,396)

Proved Developed and Undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves at December 31, 2018

 

26,130

 

25,343

 

91,496

 

658,270

 

117,626

 

683,613

 

231,562

Proved Developed Reserves

 

  

 

  

 

  

 

  

 

  

 

  

 

  

December 31, 2015

 

30,517

 

101,665

 

38,572

 

288,684

 

69,089

 

390,349

 

134,147

December 31, 2016

 

25,743

 

48,243

 

33,799

 

350,294

 

59,542

 

398,537

 

125,965

December 31, 2017

 

24,883

 

35,347

 

39,655

 

416,313

 

64,537

 

451,660

 

139,814

December 31, 2018

 

23,065

 

25,271

 

50,645

 

458,649

 

73,710

 

483,920

 

154,363

Proved Undeveloped Reserves

 

  

 

  

 

  

 

  

 

  

 

  

 

  

December 31, 2015

 

4,555

 

1,567

 

15,130

 

9,708

 

19,685

 

11,275

 

21,564

December 31, 2016

 

3,267

 

1,178

 

12,027

 

9,612

 

15,294

 

10,790

 

17,092

December 31, 2017

 

2,501

 

1,204

 

34,615

 

56,146

 

37,116

 

57,350

 

46,674

December 31, 2018

 

3,065

 

72

 

40,852

 

199,621

 

43,916

 

199,693

 

77,198

Purchases of reserves in place

In 2016, the Company acquired working interests in the Ante Creek North oil property located in Alberta. This purchase represented all of the purchase of reserves in place for Enerplus in 2016.

In 2018, the Company acquired minor working interest reserve volumes through a land swap in the Bakken/Three Forks crude oil property in North Dakota. As part of this land swap, the Company also divested an almost equal amount of working interest reserve volumes within the Bakken/Three Forks crude oil property.

 

Sales of reserves in place  

 

In 2016, the Company sold working interests in developed and undeveloped land in six oil properties located in Alberta and 12 natural gas properties located in Alberta and Saskatchewan.

 

 

Additionally, the Company sold almost all of its non-operated working interests in the Bakken/Three Forks crude oil property in North Dakota, which accounts for all of the United States sales of reserves in place for 2016.

 

In 2017, the Company sold working interests in developed and undeveloped land in nine oil properties and 39 natural gas properties located in Alberta and Saskatchewan.

 

In 2018, the company sold working interests in developed and undeveloped land in one oil property and eight natural gas properties located in Alberta.

In 2018, the Company divested minor working interest reserve volumes through a land swap in the Bakken/Three Forks crude oil property in North Dakota. As part of this land swap, the Company also acquired an almost equal amount of working interest reserve volumes within the Bakken/Three Forks crude oil property.

Discoveries and extensions

  United States discoveries and extensions in the Company's Bakken/Three Forks crude oil property in North Dakota, and the Marcellus natural gas property in Pennsylvania for the period ending December 31, 2016 were primarily due to successful well development. In 2017, discoveries and extensions in these properties were primarily due to improved constant pricing and also successful well development. In 2018, discoveries and extensions in these properties were primarily due to successful well development. In these periods, the Company added 12,515 Mbbl, 34,213 Mbbl and 24,791 Mbbl of net proved oil and NGLs reserves with respect to Bakken/Three Forks properties in 2016, 2017 and 2018, respectively. The Company added 22,017 MMcf , 34,618 MMcf and 52,880 MMcf of net proved natural gas reserves in 2016, 2017 and 2018, respectively, in the Marcellus natural gas property.

 

In 2016, Canadian discoveries and extensions accounted for an increase of 83 Mbbl of net proved oil and NGLs reserves due to assigning reserves to a location in the Saskatchewan Ratcliffe oil property.

 

In 2017, Canadian discoveries and extensions accounted for an increase of 1,373 Mbbl of net proved oil and NGLs reserves and 450 MMcf of net proved natural gas reserves in the Medicine Hat Glauconitic C polymer flood and Cadogan oil properties located in Alberta, and the Saskatchewan Ratcliffe oil property.

 

In 2018, Canadian discoveries and extensions accounted for an increase of 965 Mbbl of net proved oil and NGLs reserves and 1,180 MMcf of net proved natural gas reserves in the Med Hat Glauconitic C polymer flood and Giltedge oil properties located in Alberta, and the Saskatchewan Ratcliffe oil property.

 

Revisions of previous estimates

In 2016, negative revisions to United States oil reserves were primarily due to the removal of undeveloped locations that would not be drilled within five years of initial booking. Positive revisions to United States natural gas reserves were primarily due to improved production performance of the Marcellus natural gas property.

 

In 2017, positive revisions to United States oil reserves and United States natural gas reserves were primarily due to an increase in the constant oil price forecast versus 2016.

 

In 2018, positive revisions to United States oil reserves were primarily due to an increase in the constant oil price forecast versus 2017. Positive revisions to United States natural gas reserves were primarily due to improved production performance and also an increase in the constant gas price forecast versus 2017.

 

In 2016, the positive revisions to Canadian natural gas reserves were due to a slightly higher gas price forecast and slightly lower operating costs.

 

In 2017, the positive revisions to both Canadian oil and natural gas reserves were primarily due to an increase in the constant oil and gas price forecasts versus 2016 .

 

In 2018, the positive revisions to Canadian oil reserves were primarily due to an increase in the constant oil price forecast versus 2017. Positive revisions to Canadian natural gas reserves were primarily due to improved production performance.

 

 

Improved Recovery

In 2018 in the Ante Creek North waterflood property located in Alberta, there was an improved recovery revision of 541 Mbbl of net proved oil and NGLs reserves and 17 MMcf of net proved natural gas reserves.

 

B. CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES

The capitalized costs and related accumulated depreciation and depletion, including impairments, relating to Enerplus’ oil and gas exploration, development and producing activities are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

    

2018

    

2017

    

2016

 

 

 

(in $ thousands)

 

Capitalized costs (1)

 

$

14,773,082

 

$

13,622,266

 

$

13,567,390

 

Less accumulated depletion, depreciation and impairment

 

 

(13,479,141)

  

 

(12,732,299)

 

 

(12,840,938)

  

Net capitalized costs

 

$

1,293,941

 

$

889,967

 

$

726,452

 

Note:

(1) Includes capitalized costs of proved and unproved properties.

 

C. COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

Costs incurred in connection with oil and gas producing activities are presented in the table below. Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties, including an allocation of purchase price on business combinations that result in property acquisitions. Development costs include asset retirement costs capitalized and the costs of drilling and equipping development wells and facilities to extract, gather and store oil and gas, along with an allocation of overhead. Exploration costs include costs related to the discovery and the drilling and completion of exploratory wells in new crude oil and natural gas reservoirs.

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 2018

 

    

Canada

    

United States

    

Total

 

 

(in $ thousands) 

Acquisition of properties:

 

 

 

 

 

 

 

 

 

Proved

 

$

 —

 

$

6,055

 

$

6,055

Unproved

 

 

3,888

 

 

15,624

 

 

19,512

Exploration costs

 

 

641

 

 

979

 

 

1,620

Development costs

 

 

61,632

 

 

547,667

 

 

609,299

 

 

$

66,161

 

$

570,325

 

$

636,486

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 2017

 

    

Canada

    

United States

    

Total

 

 

(in $ thousands) 

Acquisition of properties:

 

 

 

 

 

 

 

 

 

Proved

 

$

 —

 

$

 —

 

$

 —

Unproved

 

 

4,661

 

 

8,615

 

 

13,276

Exploration costs

 

 

2,131

 

 

571

 

 

2,702

Development costs

 

 

66,477

 

 

403,798

 

 

470,275

 

 

$

73,269

 

$

412,984

 

$

486,253

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 2016

 

    

Canada

    

United States

    

Total

 

 

 

(in $ thousands) 

Acquisition of properties:

 

 

 

 

 

 

 

 

 

Proved

 

$

49,043

 

$

1,847

 

$

50,890

Unproved

 

 

65,401

 

 

9,835

 

 

75,236

Exploration costs

 

 

740

 

 

2,158

 

 

2,898

Development costs

 

 

52,704

 

 

162,427

 

 

215,131

 

 

$

167,888

 

$

176,267

 

$

344,155

 

D. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth revenue and direct cost information relating to Enerplus' oil and gas producing activities for the years ended December 31, 2018, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 2018

 

    

Canada

    

United States

    

Total

 

 

(in $ thousands) 

Revenue

 

 

 

 

 

 

 

 

 

Sales (1)

 

$

198,263

 

$

1,094,473

 

$

1,292,736

Deduct (2)

 

 

 

 

 

 

 

 

 

Production costs (3)

 

 

89,584

 

 

359,426

 

 

449,010

Depletion, depreciation and accretion (“DD&A”)

 

 

58,333

 

 

245,941

 

 

304,274

Current and deferred income tax provision (recovery)

 

 

3,515

 

 

99,696

 

 

103,211

Results of operations for oil and gas producing activities

 

$

46,831

 

$

389,410

 

$

436,241

DD&A per net BOE unit of production

 

$

12.96

 

$

10.74

 

$

11.11

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 2017

 

    

Canada

    

United States

    

Total

 

 

(in $ thousands) 

Revenue

 

 

 

 

 

 

 

 

 

Sales (1)

 

$

227,031

 

$

693,662

 

$

920,693

Deduct (2)

 

 

 

 

 

 

 

 

 

Production costs (3)

 

 

98,057

 

 

264,627

 

 

362,684

Depletion, depreciation and accretion (“DD&A”)

 

 

89,937

 

 

160,837

 

 

250,774

Current and deferred income tax provision (recovery)

 

 

(17,534)

 

 

99,522

 

 

81,988

Results of operations for oil and gas producing activities

 

$

56,571

 

$

168,676

 

$

225,247

DD&A per net BOE unit of production

 

$

15.07

 

$

8.46

 

$

10.04

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 2016

 

    

Canada

    

United States

    

Total

 

 

(in $ thousands) 

Revenue

 

 

 

 

 

 

 

 

 

Sales (1)

 

$

233,391

 

$

489,341

 

$

722,732

Deduct (2)

 

 

 

 

 

 

 

 

 

Production costs (3)

 

 

151,151

 

 

241,330

 

 

392,481

Depletion, depreciation and accretion (“DD&A”)

 

 

126,061

 

 

202,903

 

 

328,964

Impairment

 

 

89,359

 

 

211,812

 

 

301,171

Current and deferred income tax provision (recovery)

 

 

(24,376)

 

 

(212,822)

 

 

(237,198)

Results of operations for oil and gas producing activities

 

$

(108,804)

 

$

46,118

 

$

(62,686)

DD&A per net BOE unit of production

 

$

14.31

 

$

10.55

 

$

11.73

Notes:

(1)

Sales are presented net of royalties

(2)

The costs deducted in this schedule exclude corporate overhead, interest expense and other costs which are not directly related to oil and gas producing activities.

 

(3)

Production costs include operating costs, transportation costs and production taxes.

E. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL GAS RESERVE QUANTITIES

The following tables set forth the standardized measure of discounted future net cash flows from projected production of Enerplus’ crude oil and natural gas reserves:

 

 

 

 

 

 

 

 

 

 

 

    

    

 

    

    

 

    

    

    

 

 

As at December 31, 2018

 

    

Canada

 

United States

 

Total

 

 

(in $ millions)

Future cash inflows

 

$

1,350

 

$

7,090

 

$

8,440

Future production costs

 

 

643

 

 

2,109

 

 

2,752

Future development and asset retirement costs

 

 

143

 

 

1,316

 

 

1,459

Future income tax expenses

 

 

 —

 

 

508

 

 

508

Future net cash flows

 

$

564

 

$

3,158

 

$

3,722

Deduction: 10% annual discount factor

 

 

206

 

 

1,177

 

 

1,383

Standardized measure of discounted future net cash flows

 

$

357

 

$

1,981

 

$

2,338

 

 

 

 

 

 

 

 

 

 

 

 

    

    

 

    

    

 

    

    

 

 

 

As at December 31, 2017

 

    

Canada

 

United States

 

Total

 

 

(in $ millions)

Future cash inflows

 

$

1,383

 

$

4,360

 

$

5,743

Future production costs

 

 

654

 

 

1,553

 

 

2,207

Future development and asset retirement costs

 

 

126

 

 

895

 

 

1,021

Future income tax expenses

 

 

 —

 

 

24

 

 

24

Future net cash flows

 

$

603

 

$

1,888

 

$

2,491

Deduction: 10% annual discount factor

 

 

233

 

 

717

 

 

950

Standardized measure of discounted future net cash flows

 

$

370

 

$

1,171

 

$

1,540

 

 

 

 

 

 

 

 

 

 

 

 

    

    

 

    

    

 

    

    

 

 

 

As at December 31, 2016

 

    

Canada

 

United States

 

Total

 

 

(in $ millions)

Future cash inflows

 

$

1,171

 

$

2,073

 

$

3,243

Future production costs

 

 

660

 

 

1,025

 

 

1,685

Future development and asset retirement costs

 

 

237

 

 

308

 

 

546

Future income tax expenses

 

 

 —

 

 

 —

 

 

 —

Future net cash flows

 

$

273

 

$

739

 

$

1,012

Deduction: 10% annual discount factor

 

 

81

 

 

241

 

 

322

Standardized measure of discounted future net cash flows

 

$

192

 

$

498

 

$

690

 

 

F. CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND NATURAL GAS RESERVES

 

 

 

 

 

 

 

 

 

 

 

    

    

 

    

    

 

    

    

 

 

    

2018

 

2017

 

2016

 

 

(in $ millions)

Beginning of year

 

$

1,540

 

$

690

 

$

944

Sales of oil and natural gas produced, net of production costs

 

 

(844)

 

 

(557)

 

 

(329)

Net changes in sales prices and production costs

 

 

1,195

 

 

1,030

 

 

(432)

Changes in previously estimated development costs incurred during the period

 

 

594

 

 

457

 

 

205

Changes in estimated future development costs

 

 

(892)

 

 

(843)

 

 

 1

Extension, discoveries and improved recovery, net of related costs

 

 

978

 

 

455

 

 

78

Purchase of reserves in place

 

 

 2

 

 

 —

 

 

42

Sales of reserves in place

 

 

(2)

 

 

 —

 

 

(106)

Net change resulting from revisions in previous quantity estimates

 

 

(114)

 

 

262

 

 

188

Accretion of discount

 

 

143

 

 

61

 

 

79

Net change in income taxes

 

 

(247)

 

 

(8)

 

 

 —

Other significant factors (Exchange rate)

 

 

(15)

 

 

(6)

 

 

22

End of year

 

$

2,338

 

$

1,540

 

$

690

 

EXHIBIT 99.13

 

 

CONSENT OF PREDECESSOR INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

We consent to the incorporation by reference in Registration Statement No. 333-216844 on Form F-10 and Registration Statement No. 333-200583 on Form S-8; and to the use of our report dated February 24, 2017, relating to the 2016 consolidated financial statements (before the effects of the adjustments to retrospectively apply ASU 2016-18 adopted in 2017 as discussed in Note 2(f) to the consolidated financial statements of Enerplus Corporation (which report expresses an unmodified / unqualified opinion and includes an other matter paragraph regarding the retrospective adjustments reflected on such financial statements)) appearing in this Annual Report on Form 40-F of Enerplus Corporation for the year ended December 31, 2018.

 

 

 

 

 

 /s/ Deloitte LLP

 

Chartered Professional Accountants

 

Calgary, Canada

February 22, 2019

 

 

        REPORTS

Exhibit 99.2

 

Management’s Report on Internal Control over Financial Reporting

 

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision of our Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control‑Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we have concluded that as of December 31, 2018, our internal control over financial reporting is effective.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2018, has been audited by KPMG LLP, the Independent Registered Public Accounting Firm, who also audited the Company’s Consolidated Financial Statements for the year ended December 31, 2018.

 

 

 

/s/ Ian C. Dundas

/s/ Jodine J. Jenson Labrie

President and
Chief Executive Officer

Senior Vice President and
Chief Financial Officer

Calgary, Alberta

February 22, 2019

 

ENERPLUS 2018 FINANCIAL SUMMARY                 37

 

 

      

Report of Independent Registered Public Accounting Firm

 

To the Shareholders and Board of Directors of Enerplus Corporation

 

Opinion on Internal Control Over Financial Reporting

We have audited Enerplus Corporation’s (the “Corporation”) internal control over financial reporting as of December 31, 2018, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Corporation as of December 31, 2018 and 2017, the related consolidated statements of income (loss) and comprehensive income (loss), changes in shareholders’ equity and cash flows for the years then ended, and the related notes, comprising a summary of significant accounting policies and other explanatory information (collectively referred to as the “consolidated financial statements”) and our report dated February 22, 2019 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control and Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.  

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

/s/ KPMG LLP

Chartered Professional Accountants
Calgary, Canada
February 22, 2019

 

38                 ENERPLUS 2018 FINANCIAL SUMMARY  

 

 

      

Management’s Responsibility for Financial Statements

 

In management’s opinion, the accompanying consolidated financial statements of Enerplus Corporation have been prepared within reasonable limits of materiality and in accordance with accounting principles generally accepted in the United States of America. Since a precise determination of many assets and liabilities is dependent on future events, the preparation of financial statements necessarily involves the use of estimates and approximations. These have been made using careful judgment and with all information available up to February 21, 2019. Management is responsible for all information in the annual report and for the consistency, therewith, of all other financial and operating data presented in this report.

To meet its responsibility for reliable and accurate financial statements, management has established and monitors systems of internal control which are designed to provide reasonable assurance that financial information is relevant, reliable and accurate, and that assets are safeguarded and transactions are executed in accordance with management’s authorization.

The consolidated financial statements have been examined by KPMG LLP, Independent Registered Public Accountants. Their responsibility is to express a professional opinion on the fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. The Report of Independent Registered Public Accounting Firm outlines the scope of their examination and sets forth their opinion.

The Audit Committee, consisting exclusively of independent directors, has reviewed these statements with management and the Independent Registered Public Accounting Firm and has recommended their approval to the Board of Directors. The Board of Directors has approved the consolidated financial statements of the Company.

 

 

 

/s/ Ian C. Dundas

/s/ Jodine J. Jenson Labrie

President and
Chief Executive Officer

Senior Vice President and
Chief Financial Officer

 

Calgary, Alberta

February 22, 2019

 

 

ENERPLUS 2018 FINANCIAL SUMMARY                 39

 

 

      

Report of Independent Registered Public Accounting Firm

 

To the Shareholders and Board of Directors of Enerplus Corporation

 

Opinion on the Consolidated Financial Statements

 

We have audited the accompanying consolidated balance sheets of Enerplus Corporation (the “Corporation”) as of December 31, 2018 and 2017, the consolidated statements of income (loss) and comprehensive income (loss), changes in shareholders’ equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Corporation as of December 31, 2018 and 2017, and the results of operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 22, 2019 expressed an unqualified opinion on the effectiveness of the Corporation’s internal control over financial reporting.

 

Basis for Opinion

 

These consolidated financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

 

Comparative information

 

The consolidated financial statements of the Corporation for the year ended December 31, 2016, excluding the impact of adoption of ASU 2016-18 as described in Note 2(f) to the consolidated financial statements, were audited by another auditor who expressed an unqualified (unmodified) opinion on the consolidated financial statements on February 24, 2017.

 

As part of our audits of the consolidated financial statements as at and for the years ended December 31, 2018 and 2017, we audited the adoption of ASU 2016-18 as described in Note 2(f) to the consolidated financial statements that was applied to amend the comparative information presented for the year ended December 31, 2016. In our opinion, the adoption of ASU 2016-18 has been properly applied.

 

We were not engaged to audit, review, or apply any procedures to the consolidated financial statements of the Corporation for the year ended December 31, 2016, other than with respect to the amendment described in Note 2(f) to the consolidated financial statements. Accordingly, we do not express an opinion or any other form of assurance on those financial statements taken as a whole.

We have served as the Corporation’s auditor since 2017.

 

/s/ KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 22, 2019

40                 ENERPLUS 2018 FINANCIAL SUMMARY  

 

 

      

Report of Independent Registered Public Accounting Firm

 

To the Shareholders and Board of Directors of Enerplus Corporation

We have audited, before the effects of the adjustments to retrospectively apply ASU 2016-18 adopted in 2017 as discussed in Note 2(f) to the consolidated financial statements, the accompanying consolidated financial statements of Enerplus Corporation and subsidiaries (the “Company”), which comprise the consolidated statements of income/(loss) and comprehensive income/(loss), consolidated statements of changes in shareholders’ equity, and consolidated statements of cash flows for the year ended December 31, 2016, and the notes to the consolidated financial statements.

 

Management’s Responsibility for the Consolidated Financial Statements

 

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

 

Auditor’s Responsibility

 

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

 

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

 

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

 

Opinion

 

In our opinion, such consolidated financial statements, before the effects of the adjustments to retrospectively apply ASU 2016-18 adopted in 2017 as discussed in Note 2(f) to the consolidated financial statements, present fairly, in all material respects, the financial performance and cash flows of Enerplus Corporation and subsidiaries for the year ended December 31, 2016 in accordance with accounting principles generally accepted in the United States of America.

 

Other Matter

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively adopt ASU 2016-18 as discussed in Note 2(f) to the consolidated financial statements and, accordingly, we do not express an opinion or any other form of assurance about whether such retrospective adjustments are appropriate and have been properly applied. Those retrospective adjustments were audited by other auditors.

 

/s/ Deloitte LLP

 

Chartered Professional Accountants

February 24, 2017

 

 

 

ENERPLUS 2018 FINANCIAL SUMMARY                 41

 

 

      STATEMENTS

 

Consolidated Balance Sheets

 

 

 

 

 

 

 

 

 

(CDN$ thousands)

    

Note

    

December 31, 2018

    

December 31, 2017

Assets

 

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

 

$

363,327

 

$

346,548

Accounts receivable

 

 3

 

 

145,206

 

 

129,386

Income tax receivable

 

12

 

 

55,172

 

 

1,190

Derivative financial assets

 

14(b)

 

 

59,258

 

 

3,852

Other current assets

 

 

 

 

8,928

 

 

5,902

 

 

 

 

 

631,891

 

 

486,878

Property, plant and equipment:

 

 

 

 

 

 

 

 

Oil and natural gas properties (full cost method)

 

 4

 

 

1,293,941

 

 

889,967

Other capital assets, net

 

 4

 

 

13,130

 

 

10,064

Property, plant and equipment

 

 

 

 

1,307,071

 

 

900,031

Goodwill

 

5(b)

 

 

654,799

 

 

638,878

Derivative financial assets

 

14(b)

 

 

32,220

 

 

 —

Deferred income tax asset

 

12

 

 

465,124

 

 

569,937

Income tax receivable

 

12

 

 

27,195

 

 

50,108

Total Assets

 

 

 

$

3,118,300

 

$

2,645,832

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

 

Accounts payable

 

 6

 

$

290,045

 

$

213,978

Dividends payable

 

 

 

 

2,395

 

 

2,421

Current portion of long-term debt

 

7, 14(a)

 

 

60,001

 

 

27,656

Derivative financial liabilities

 

14(b)

 

 

1,909

 

 

28,642

 

 

 

 

 

354,350

 

 

272,697

Derivative financial liabilities

 

14(b)

 

 

 —

 

 

9,907

Long-term debt

 

7, 14(a)

 

 

636,849

 

 

644,723

Asset retirement obligation

 

 8

 

 

126,112

 

 

117,736

 

 

 

 

 

762,961

 

 

772,366

Total Liabilities

 

 

 

 

1,117,311

 

 

1,045,063

 

 

 

 

 

 

 

 

 

Shareholders’ Equity

 

 

 

 

 

 

 

 

Share capital – authorized unlimited common shares, no par value

 

 

 

 

 

 

 

 

Issued and outstanding:  December 31, 2018 – 239 million shares

 

 

 

 

 

 

 

 

 December 31, 2017 – 242 million shares

 

13(a)

 

 

3,337,608

 

 

3,386,946

Paid-in capital

 

 

 

 

46,524

 

 

75,375

Accumulated deficit

 

 

 

 

(1,772,084)

 

 

(2,124,676)

Accumulated other comprehensive income

 

 

 

 

388,941

 

 

263,124

 

 

 

 

 

2,000,989

 

 

1,600,769

Total Liabilities & Shareholders' Equity

 

 

 

$

3,118,300

 

$

2,645,832

 

 

 

 

 

 

 

 

 

Commitments and Contingencies

 

15

 

 

 

 

 

 

Subsequent Event

 

13(a)

 

 

 

 

 

 

 

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

 

Approved on behalf of the Board of Directors:

 

 

/s/ Elliott Pew

/s/ Robert B. Hodgins

Director

Director

 

 

 

42                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

 

Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)

 

 

 

 

 

 

 

 

 

 

 

 

For the year ended December 31 (CDN$ thousands)

    

Note

    

2018

    

2017

    

2016

Revenues

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales, net of royalties

 

 9

 

$

1,292,736

 

$

920,693

 

$

722,732

Commodity derivative instruments gain/(loss)

 

14(b)

 

 

88,232

 

 

14,310

 

 

(29,397)

 

 

 

 

 

1,380,968

 

 

935,003

 

 

693,335

Expenses

 

 

 

 

 

 

 

 

 

 

 

Operating

 

 

 

 

238,261

 

 

197,101

 

 

247,917

Transportation

 

 

 

 

123,463

 

 

111,265

 

 

107,147

Production taxes

 

 

 

 

87,286

 

 

54,318

 

 

37,417

General and administrative

 

10

 

 

75,783

 

 

74,301

 

 

86,319

Depletion, depreciation and accretion

 

 

 

 

304,274

 

 

250,774

 

 

328,964

Asset impairment

 

5(a)

 

 

 —

 

 

 —

 

 

301,171

Interest

 

 

 

 

36,799

 

 

38,714

 

 

45,443

Foreign exchange (gain)/loss

 

11

 

 

39,521

 

 

(30,150)

 

 

(40,526)

Gain on divestment of assets

 

 4

 

 

 —

 

 

(78,400)

 

 

(559,235)

Gain on prepayment of senior notes

 

 7

 

 

 —

 

 

 —

 

 

(19,270)

Other expense /(income)

 

 

 

 

(5,909)

 

 

(1,906)

 

 

(2,230)

 

 

 

 

 

899,478

 

 

616,017

 

 

533,117

Income/(Loss) Before Taxes

 

 

 

 

481,490

 

 

318,986

 

 

160,218

Current income tax expense/(recovery)

 

12

 

 

(27,093)

 

 

(47,957)

 

 

(2,351)

Deferred income tax expense/(recovery)

 

12

 

 

130,304

 

 

129,945

 

 

(234,847)

Net Income/(Loss)

 

 

 

$

378,279

 

$

236,998

 

$

397,416

 

 

 

 

 

 

 

 

 

 

 

 

Other Comprehensive Income/(Loss)

 

 

 

 

 

 

 

 

 

 

 

Change in cumulative translation adjustment

 

 

 

 

125,817

 

 

(90,277)

 

 

(49,271)

Total Comprehensive Income/(Loss)

 

 

 

$

504,096

 

$

146,721

 

$

348,145

 

 

 

 

 

 

 

 

 

 

 

 

Net Income/(Loss) per Share

 

 

 

 

 

 

 

 

 

 

 

Basic

 

13(c)

 

$

1.55

 

$

0.98

 

$

1.75

Diluted

 

13(c)

 

$

1.53

 

$

0.96

 

$

1.72

 

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements .

ENERPLUS 2018 FINANCIAL SUMMARY                 43

 

 

      

 

Consolidated Statements of Changes in Shareholders’ Equity

 

 

 

 

 

 

 

 

 

 

For the year ended December 31 (CDN$ thousands)

    

2018

    

2017

    

2016

Share Capital

 

 

 

 

 

 

 

 

 

Balance, beginning of year

 

$

3,386,946

 

$

3,365,962

 

$

3,133,524

Public offering (net of issue costs)

 

 

 —

 

 

 —

 

 

223,031

Purchase of common shares under Normal Course Issuer Bid

 

 

(82,596)

 

 

 —

 

 

 —

Share-based compensation – settled

 

 

23,389

 

 

20,984

 

 

9,407

Stock Option Plan – cash

 

 

9,138

 

 

 —

 

 

 —

Stock Option Plan – exercised

 

 

731

 

 

 —

 

 

 —

Balance, end of year

 

$

3,337,608

 

$

3,386,946

 

$

3,365,962

 

 

 

 

 

 

 

 

 

 

Paid-in Capital

 

 

 

 

 

 

 

 

 

Balance, beginning of year

 

$

75,375

 

$

73,783

 

$

56,176

Share-based compensation – cash settled

 

 

(30,648)

 

 

 —

 

 

 —

Share-based compensation – non-cash settled

 

 

(23,389)

 

 

(20,984)

 

 

(9,407)

Share-based compensation – non-cash

 

 

25,917

 

 

22,576

 

 

27,014

Stock Option Plan – exercised

 

 

(731)

 

 

 —

 

 

 —

Balance, end of year

 

$

46,524

 

$

75,375

 

$

73,783

 

 

 

 

 

 

 

 

 

 

Accumulated Deficit

 

 

 

 

 

 

 

 

 

Balance, beginning of year

 

$

(2,124,676)

 

$

(2,332,641)

 

$

(2,694,618)

Purchase of common shares under Normal Course Issuer Bid

 

 

3,569

 

 

 —

 

 

 —

Net income/(loss)

 

 

378,279

 

 

236,998

 

 

397,416

Dividends declared

 

 

(29,256)

 

 

(29,033)

 

 

(35,439)

Balance, end of year

 

$

(1,772,084)

 

$

(2,124,676)

 

$

(2,332,641)

 

 

 

 

 

 

 

 

 

 

Accumulated Other Comprehensive Income

 

 

 

 

 

 

 

 

 

Balance, beginning of year

 

$

263,124

 

$

353,401

 

$

402,672

Change in cumulative translation adjustment

 

 

125,817

 

 

(90,277)

 

 

(49,271)

Balance, end of year

 

$

388,941

 

$

263,124

 

$

353,401

Total Shareholders’ Equity

 

$

2,000,989

 

$

1,600,769

 

$

1,460,505

 

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

44                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

 

Consolidated Statements of Cash Flows

 

 

 

 

 

 

 

 

 

 

 

 

For the year ended December 31 (CDN$ thousands)

    

Note

    

2018

    

2017

    

2016

Operating Activities

 

 

 

 

 

 

 

 

 

 

 

Net income/(loss)

 

 

 

$

378,279

 

$

236,998

 

$

397,416

Non-cash items add/(deduct):

 

 

 

 

 

 

 

 

 

 

 

Depletion, depreciation and accretion

 

 

 

 

304,274

 

 

250,774

 

 

328,964

Asset impairment

 

5(a)

 

 

 —

 

 

 —

 

 

301,171

Changes in fair value of derivative instruments

 

14(b)

 

 

(124,266)

 

 

(6,184)

 

 

105,026

Deferred income tax expense/(recovery)

 

12

 

 

130,304

 

 

129,945

 

 

(234,847)

Foreign exchange (gain)/loss on debt and working capital

 

11

 

 

58,628

 

 

(42,623)

 

 

(40,634)

Share-based compensation

 

13(b)

 

 

25,917

 

 

22,576

 

 

27,014

Translation of U.S. dollar cash held in Canada (gain)/loss

 

11

 

 

(19,630)

 

 

10,978

 

 

 —

Gain on the divestment of assets

 

 4

 

 

 —

 

 

(78,400)

 

 

(559,235)

Gain on prepayment of senior notes

 

 7

 

 

 —

 

 

 —

 

 

(19,270)

Asset retirement obligation expenditures

 

 8

 

 

(11,263)

 

 

(12,907)

 

 

(8,390)

Changes in non-cash operating working capital

 

17(a)

 

 

(3,459)

 

 

(35,032)

 

 

15,075

Cash flow from operating activities

 

 

 

 

738,784

 

 

476,125

 

 

312,290

 

 

 

 

 

 

 

 

 

 

 

 

Financing Activities

 

 

 

 

 

 

 

 

 

 

 

Proceeds from the issuance of shares (net of issue costs)

 

13(a)

 

 

9,138

 

 

 —

 

 

220,410

Dividends

 

13(a),17(b)

 

 

(29,282)

 

 

(29,017)

 

 

(39,230)

Bank credit facility

 

 7

 

 

 —

 

 

(23,272)

 

 

(55,999)

Senior notes

 

 7

 

 

(29,044)

 

 

(29,084)

 

 

(335,400)

Purchase of common shares under Normal Course Issuer Bid

 

13(a)

 

 

(79,027)

 

 

 —

 

 

 —

Cash flow from/(used in) financing activities

 

 

 

 

(128,215)

 

 

(81,373)

 

 

(210,219)

 

 

 

 

 

 

 

 

 

 

 

 

Investing Activities

 

 

 

 

 

 

 

 

 

 

 

Capital and office expenditures

 

17(b)

 

 

(604,110)

 

 

(459,152)

 

 

(260,083)

Property and land acquisitions

 

 4

 

 

(18,009)

 

 

(13,276)

 

 

(126,126)

Property divestments

 

 4

 

 

(919)

 

 

56,196

 

 

670,364

Cash flow from/(used in) investing activities

 

 

 

 

(623,038)

 

 

(416,232)

 

 

284,155

Effect of exchange rate changes on cash and cash equivalents

 

 

 

 

29,248

 

 

(25,277)

 

 

(419)

Change in cash and cash equivalents

 

 

 

 

16,779

 

 

(46,757)

 

 

385,807

Cash and cash equivalents, beginning of year

 

 

 

 

346,548

 

 

393,305

 

 

7,498

Cash and cash equivalents, end of year

 

 

 

$

363,327

 

$

346,548

 

$

393,305

 

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements .

 

 

ENERPLUS 2018 FINANCIAL SUMMARY                 45

 

 

      NOTES

 

Notes to Consolidated Financial Statements

1) REPORTING ENTITY

These annual audited Consolidated Financial Statements (“Consolidated Financial Statements”) and notes present the financial position and results of Enerplus Corporation (the “Company” or “Enerplus”) including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus’ head office is located in Calgary, Alberta, Canada.

2) SIGNIFICANT ACCOUNTING POLICIES

The following significant accounting policies are presented to assist the reader in evaluating these Consolidated Financial Statements and, together with the following notes, are an integral part of the Consolidated Financial Statements.

a) Basis of Preparation

Enerplus’ Consolidated Financial Statements have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Certain prior period amounts have been restated to conform with current period presentation.  

i. Reporting Currency

These Consolidated Financial Statements are presented in Canadian dollars, which is Enerplus’ reporting currency. All financial information presented in Canadian dollars has been rounded to the nearest thousand unless otherwise indicated.

ii. Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Actual results could differ from these estimates, and changes in estimates are recorded when known. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows, depreciation, depletion and accretion (“DD&A”), impairment, asset retirement obligations, income taxes, income tax asset values, impairment assessments of goodwill and the fair value of derivative instruments. Enerplus uses the most current information available and exercises judgment in making these estimates and assumptions. In the opinion of management, these Consolidated Financial Statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies.

iii. Basis of Consolidation

These Consolidated Financial Statements include the accounts of Enerplus and its subsidiaries. Intercompany balances and transactions are eliminated on consolidation. Interests in jointly controlled oil and natural gas assets are accounted for following the concept of undivided interest, whereby Enerplus’ proportionate share of revenues, expenses, assets and liabilities are included in the accounts.

The acquisition method of accounting is used to account for acquisitions that meet the definition of a business under U.S. GAAP. The cost of an acquisition is measured as the fair value of the assets transferred, equity instruments issued and liabilities incurred or assumed at the acquisition date. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.

b) Revenue

Revenue from the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers, net of sales taxes. Enerplus recognizes revenue when it satisfies a performance obligation by transferring control of the product to a customer. This is generally at the time the customer obtains legal title to the product and when it is physically transferred to the contractual delivery points.

 

Enerplus evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent.  In making this evaluation, management considers if Enerplus retains control of the product being delivered to the end customer. As part of this assessment, management considers whether the Company retains the economic benefits associated with the good being delivered to the end customer. Management also considers whether the Company has the primary responsibility for the delivery of the product, the ability to establish prices or the inventory risk. If Enerplus acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net basis, only reflecting the fee, if any, realized by the Company from the transaction.

46                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

c) Transportation

Enerplus generally sells oil and natural gas under two types of agreements which are common in our industry.  Both types of agreements include a transportation charge.  One is a net-back arrangement, under which the Company sells crude oil or natural gas at the wellhead and collects a price, net of the transportation incurred by the purchaser.  In this case, sales are recorded at the price received from the purchaser, net of transportation costs. 

Under the other arrangement, Enerplus sells crude oil or natural gas at a specific delivery point, pays transportation to a third party and receives proceeds from the purchaser with no transportation deduction.  In this case, transportation costs are recorded as transportation expense on the Consolidated Statements of Income/(Loss).  Due to these two distinct selling arrangements, Enerplus’ computed realized prices, before the impact of derivative instruments, include revenues which are reported under two separate bases.

d) Oil and Natural Gas Properties

Enerplus uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs incurred in finding oil and natural gas reserves are capitalized, including general and administrative costs directly attributable to these activities. These costs are recorded on a country‑by‑country cost centre basis as oil and natural gas properties subject to depletion (“full cost pool”). Costs associated with production and general corporate activities are expensed as incurred.

The net carrying value of both proved and unproved oil and natural gas properties is depleted using the unit of production method using proved reserves, as determined using a constant price assumption of the simple average of the preceding twelve months’ first-day-of-the-month commodity prices (“SEC prices”). The depletion calculation takes into account estimated future development costs necessary to bring those reserves into production.

Under full cost accounting, a ceiling test is performed on a cost centre basis. Enerplus limits capitalized costs of proved and unproved oil and natural gas properties, net of accumulated depletion and deferred income tax liabilities, to the estimated future net cash flows from proved oil and natural gas reserves discounted at 10%, net of related tax effects, plus the lower of cost or fair value of unproved properties (“the ceiling”). The estimated future net cash flows are calculated using the simple average of the preceding twelve months’ first-day-of-the-month commodity prices. If such capitalized costs exceed the ceiling, a write-down equal to that excess is recorded as a non-cash charge to net income. A write-down is not reversed in future periods even if higher oil and natural gas prices subsequently increase the ceiling.

Under full cost accounting rules, divestitures of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss.  However, if not recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized.

 

e) Other Capital Assets

Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements and computer equipment. Depreciation is calculated on a straight-line basis over the estimated useful life of the respective asset. The cost of repairs and maintenance is expensed as incurred.

f) Cash and Cash Equivalents and Restricted Cash

Cash and cash equivalents includes cash and highly liquid investments with original maturities of less than 90 days.

In 2017, Enerplus adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. As a result of the adoption of ASU 2016-18, restricted cash of $392.0 million at December 31, 2016 has been included in cash and cash equivalents on the Consolidated Statements of Cash Flows, with a corresponding increase to change in cash and cash equivalents. Prior to adoption, changes in restricted cash were included in investing activities. Enerplus’ 2016 Consolidated Statement of Cash Flows was restated as required to reflect this change in presentation.

g) Goodwill

Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. The portion of goodwill that relates to U.S. operations fluctuates due to changes in foreign exchange rates. Goodwill is stated at cost less impairment and is not amortized. Goodwill is not deductible for income tax purposes.   

Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. Enerplus first performs a qualitative assessment to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value,

ENERPLUS 2018 FINANCIAL SUMMARY                 47

 

 

      

quantitative impairment tests are performed.  If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings in the Consolidated Statements of Income/(Loss). For the purposes of goodwill impairment testing, Enerplus has two reporting units. The change in goodwill in 2018 and 2017 related to the impact of foreign exchange movements on U.S. dollar denominated goodwill balances. No impairment has been recorded in 2018, 2017 or 2016.

h) Asset Retirement Obligations

Enerplus’ oil and natural gas operating activities give rise to dismantling, decommissioning and site remediation activities. Enerplus recognizes a liability for the estimated present value of the future asset retirement obligation liability at each balance sheet date. Upon recognition, the liability is recorded at its estimated fair value. The associated asset retirement cost is capitalized and amortized over the same period as the underlying asset. Changes in the estimated liability and related asset retirement cost can arise as a result of revisions in the estimated amount or timing of cash flows.

Depletion of asset retirement costs and increases in asset retirement obligations resulting from the passage of time are recorded to depreciation, depletion and accretion and charged against net income in the Consolidated Statements of Income/(Loss).

i) Income Tax

Enerplus uses the liability method of accounting for income taxes. Deferred income tax assets and liabilities are recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax assets are reviewed each period and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized. Enerplus considers both positive and negative evidence including historic and expected future taxable income, reversing existing temporary differences and tax basis carry forward periods in making this assessment. A valuation allowance is removed in any period where available evidence indicates all or a portion of the valuation allowance is no longer required.  The financial statement effect of an uncertain tax position is recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. Penalties and interest related to income tax are recognized in income tax expense.

j) Financial Instruments

i. Fair Value Measurements

Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. For financial instruments carried at fair value, and when disclosing the fair value of financial instruments on certain non-financial items, inputs used in determining the fair value are characterized according to the following fair value hierarchy:

   Level 1  –  Inputs represent quoted market prices in active markets for identical assets or liabilities.

   Level 2  –  Inputs other than quoted market prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, such as quoted market prices for similar assets or liabilities in active markets or other market corroborated inputs.

   Level 3  – Inputs that are not observable from objective sources, such as forward prices supported by little or no market activity or internally developed estimates of future cash flows used in a present value model.

Subsequent measurement is based on classification of the financial instrument into one of the following five categories: held-for-trading, held-to-maturity, available-for-sale, loans and receivables or other financial liabilities.

ii. Non-derivative financial instruments

The carrying amount of cash, accounts receivable, income tax receivable, accounts payable, dividends payable and bank credit facilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of the senior notes are considered a level 2 fair value measurement. The fair value of debt has been disclosed in Note 14. 

iii. Derivative financial instruments

Enerplus enters into financial derivative contracts in order to manage its exposure to market risks from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. Enerplus has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though it considers most of these contracts to be economic hedges. As a result, all financial derivative contracts are classified as held-for-trading and are recorded at fair value based on a Level 2 designation, with changes in fair value recorded in net income. The fair values of these derivative instruments are generally based on an estimate of the amounts that would be paid or received to settle these

48                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

instruments at the balance sheet date. Enerplus’ accounting policy is to not offset the fair values of its financial derivative assets and liabilities.

Realized gains and losses from commodity price risk management activities are recognized in income when the contract is settled. Unrealized gains and losses on commodity price risk management activities are recognized in income based on the changes in fair value of the contracts at the end of the respective reporting period.

Enerplus’ crude oil, natural gas and natural gas liquids physical delivery purchase and sales contracts qualify as normal purchases and sales as they are entered into and held for the purpose of receipt or delivery of products in accordance with the Company’s expected purchase, sale or usage requirements. As such, these contracts are not considered derivative financial instruments. Settlements on these physical contracts are recognized in net income over the term of the contracts as they occur.

k) Foreign Currency

i. Foreign currency transactions

Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars) using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency of the entity using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Foreign currency differences arising on translation are recognized in net income in the period in which they arise.

ii. Foreign operations

Assets and liabilities of Enerplus’ U.S. operations, which has a U.S. dollar functional currency, are translated into Canadian dollars at period end exchange rates while revenues and expenses are translated using average rates for the period. Gains and losses from the translation are deferred and included in the cumulative translation adjustment which is recorded in accumulated other comprehensive income.

l) Share-Based Compensation

Enerplus’ share-based compensation plans include its equity-settled Restricted Share Unit (“RSU”) and Performance Share Unit (“PSU”) plans. The Company is authorized to issue up to 3.8% of outstanding common shares from treasury in relation to these  plans. Enerplus also has a cash-settled Deferred Share Unit (“DSU”) plan.

Enerplus’ Stock Option Plan was suspended in 2014 and is now closed.

i. RSU, PSU, and DSU plans

Under Enerplus’ RSU plan, employees receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded varies by individual and vests one-third each year for three years. The value upon vesting is based on the value of the underlying notional shares plus notional accrued dividends over the vesting period.

Under Enerplus’ PSU plan, executives and management receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded varies by individual and they vest at the end of three years. The value upon vesting is based on value of the underlying shares plus notional accrued dividends along with a multiplier that ranges from 0 to 2 depending on Enerplus’ performance compared to the TSX oil and gas index over the vesting period.

Under Enerplus’ DSU plan, directors receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded is based on the annual retainer value and they vest upon the director leaving the Board. The value upon vesting is based on the value of the underlying notional shares plus notional accrued dividends over the vesting period. All DSU grants are settled in cash.

Enerplus recognizes non-cash share-based compensation expense over the vesting period of the equity-settled long-term incentive plans, net of estimated forfeitures, based on the estimated grant date fair value of the respective awards.  Share-based compensation charges are recorded on the Consolidated Statements of Income/(Loss) with an offset to paid-in capital.  Each period, management performs an estimate of the PSU plan multiplier. Any differences that arise between the actual multiplier on plan settlement and management’s estimate is recorded to share-based compensation. On settlement of these plans, amounts previously recorded to paid-in capital are reclassified to share capital.

ENERPLUS 2018 FINANCIAL SUMMARY                 49

 

 

      

Enerplus recognizes a liability in respect of its cash-settled long-term incentive plans based on their estimated fair value. The liability is re-measured at each reporting date and at settlement date with any changes in the fair value recorded as share-based compensation, included in general and administrative expense. 

ii. Stock options

Enerplus’ Stock Option Plan was suspended in 2014 and is now closed. All options outstanding under the plan are fully vested and the expense has been fully recognized.

m) Net Income Per Share

Basic net income per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period.

For the diluted net income per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income. The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all stock options and outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price.

n) Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recognized when it is probable that a liability has been incurred and the amount can be reasonably estimated. Contingencies are adjusted as additional information becomes available or circumstances change.

o) Accounting Changes and Recent Pronouncements Issued

i. Recently adopted accounting standards

Except for the changes below, the Company has consistently applied the accounting policies to all periods presented in these Consolidated Financial Statements.

 

Enerplus adopted ASC 606 Revenue from contracts with customers effective January 1, 2018 as detailed in Note 2(b). Enerplus used the modified retrospective method to adopt the new standard, with ASC 606 applied to all contracts not yet completed as of the date of adoption with the cumulative effect on comparative periods reflected as an adjustment to retained earnings. The adoption of the new standard had no impact on the Consolidated Financial Statements, with the exception of the additional disclosures which are detailed in Note 9.

 

Management has applied the following practical expedients as part of the adoption of the standard:

 

·

No changes have been made to the revenue recognized under the previous revenue standard for contracts that were    completed during the comparative  period; and

·

The effect of contract modifications before the beginning of the comparative reporting period have not been evaluated  separately. Instead, Enerplus has reflected the aggregated effect of those modifications when identifying the performance obligations, determining the transaction price and allocating the transaction price to the satisfied and unsatisfied performance obligations.

 

ii. Future accounting changes

In future accounting periods, the Company will adopt the following Accounting Standards Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”): 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The ASU introduced a lessee accounting model that requires lessees to recognize a right-of-use (ROU) asset and related lease liability on the balance sheet for all leases, including operating leases. The FASB further issued several ASUs in 2018 which provide clarification on implementation of the new standard, technical corrections, improvements and practical expedients that can be applied under certain circumstances. The standard does not apply to oil and gas exploration rights, intangible assets or inventory. The new standard also expands disclosures related to the amount, timing and uncertainty of cash flows arising from leases. The standard will be applied using a modified retrospective approach using either 1) the effective date or 2) the beginning of the earliest comparative period presented in the financial statements as the Company’s date of initial adoption. The Company is required to adopt the new standard on January 1, 2019 and will use the effective date as its date of initial application. The standard also provides for certain practical expedients at the date of adoption and for an entity’s ongoing accounting. The Company currently expects to elect the practical expedient pertaining to land easements and the short-term lease recognition exemption which allows it to not recognize ROU assets or lease liabilities for leases with a term shorter than twelve months.

 

50                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

The Company has developed an inventory of existing lease agreements, and expects that there will be a material impact on its Consolidated Financial Statements. While the Company continues to finalize the impact of adoption, the most significant effects relate to 1) the recognition of new ROU assets and lease liabilities on the Balance Sheet for office and drilling rig operating leases and 2) providing significant new disclosures about the Company’s leasing activities. The Company continues to address system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new standard. On adoption, we currently expect to recognize lease liabilities ranging from $40.0 million to $45.0 million, with corresponding ROU assets within the same range.

 

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326) . The ASU significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020, and will be applied using a modified retrospective approach. Enerplus does not expect to early adopt the standard and continues to assess the impact to the Consolidated Financial Statements.

 

In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350) . This standard eliminates Step 2 of the goodwill impairment test, and requires a goodwill impairment charge for the amount that the carrying amount of the reporting unit exceeds the reporting unit’s fair value. The updated guidance is effective January 1, 2020, and will be applied prospectively. Enerplus does not expect to early adopt the standard. The amended standard may affect goodwill impairment tests post the adoption date, the impact of which is not known.

 

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815), making more hedging strategies eligible for hedge accounting. The new guidance is effective January 1, 2019, and will be applied prospectively. Hedge accounting continues to be an elective accounting policy choice. Enerplus does not currently apply hedge accounting, and therefore does not expect this ASU to have a material impact to its Consolidated Financial Statements.

 

3) ACCOUNTS RECEIVABLE

 

 

 

 

 

 

 

($ thousands)

   

December 31, 2018

   

December 31, 2017

Accrued revenue

 

$

118,821

 

$

102,051

Accounts receivable – trade

 

 

30,252

 

 

30,787

Allowance for doubtful accounts

 

 

(3,867)

 

 

(3,452)

Total accounts receivable, net of allowance for doubtful accounts

 

$

145,206

 

$

129,386

 

 

 

4) PROPERTY, PLANT AND EQUIPMENT (“PP&E”)

 

 

 

 

 

 

 

 

 

 

 

    

 

 

    

Accumulated Depletion,

    

 

 

As at December 31, 2018

 

 

 

 

Depreciation,

 

 

 

($ thousands)

 

Cost

 

and Impairment

 

Net Book Value

Oil and natural gas properties (1)

 

$

14,773,082

 

$

(13,479,141)

 

$

1,293,941

Other capital assets

 

 

115,510

 

 

(102,380)

 

 

13,130

Total PP&E

 

$

14,888,592

 

$

(13,581,521)

 

$

1,307,071

 

 

 

 

 

 

 

 

 

 

 

 

    

 

 

    

Accumulated Depletion,

    

 

 

As at December 31, 2017

 

 

 

 

Depreciation,

 

 

 

($ thousands)

 

Cost

 

and Impairment

 

Net Book Value

Oil and natural gas properties (1)

 

$

13,622,266

 

$

(12,732,299)

 

$

889,967

Other capital assets

 

 

107,582

 

 

(97,518)

 

 

10,064

Total PP&E

 

$

13,729,848

 

$

(12,829,817)

 

$

900,031

(1)

All of the Company’s unproved properties are included in the full cost pool.

Acquisitions:

For the years ended December 31, 2018 and 2017, Enerplus acquired property and land totaling $25.8 million, and $13.3 million, respectively. 

 

 

 

 

 

ENERPLUS 2018 FINANCIAL SUMMARY                 51

 

 

      

Divestments:

For the years ended December 31, 2018 and 2017, Enerplus disposed of properties for proceeds of $6.9 million and $56.2 million, respectively. Certain asset divestments may result in gains if the divestments cause a significant alteration in the relationship between the cost centre’s capitalized costs and proved reserves. During 2018, Enerplus did not recognize any gains on asset divestments (2017 – $78.4 million, 2016 – $559.2 million). 

 

 

 

 

 

5) IMPAIRMENT

a) Impairment of PP&E

There was no impairment recorded for the years ended December 31, 2018 and 2017. The $301.2 million impairment for the year ended December 31, 2016 was due to lower 12-month average trailing crude oil and natural gas prices.

The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling test as at December 31,   2018, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

 

    

 

 

    

 

 

    

 

U.S. Henry

    

AECO Natural

 

 

WTI Crude Oil

 

Exchange Rate

 

Edm Light Crude

 

 Hub Gas

 

Gas Spot

Period

 

US$/bbl

 

US$/CDN

 

CDN$/bbl

 

US$/Mcf

 

CDN$/Mcf

2018

 

$

65.56

 

 

1.28

 

$

69.58

 

$

3.10

 

$

1.67

2017

 

 

51.34

 

 

1.30

 

 

63.57

 

 

2.98

 

 

2.32

2016

 

 

42.75

 

 

1.32

 

 

52.26

 

 

2.49

 

 

2.17

 

b) Goodwill Impairment

Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. 

There were no additions or impairments to goodwill for the year ended December 31, 2018 or the comparative years.

 

6) ACCOUNTS PAYABLE

 

 

 

 

 

 

 

($ thousands)

    

December 31, 2018

   

December 31, 2017

Accrued payables

 

$

115,388

 

$

96,743

Accounts payable – trade

 

 

174,657

 

 

117,235

Total accounts payable

 

$

290,045

 

$

213,978

 

 

7) DEBT

 

 

 

 

 

 

 

($ thousands)

 

December 31, 2018

  

December 31, 2017

Current:

 

 

 

 

 

 

Senior notes

 

$

60,001

 

$

27,656

Long-term:

 

 

 

 

 

 

Bank credit facility

 

$

 —

 

$

 —

Senior notes

 

 

636,849

 

 

644,723

Total debt

 

$

696,850

 

$

672,379

Bank Credit Facility

Enerplus has a senior unsecured, covenant‑based, $800 million bank credit facility that matures on October 31, 2021. Drawn fees range between 1 25 and 315 basis points over bankers’ acceptance rates. Standby fees on the undrawn portion of the facility are based on 20% of the drawn pricing. The Company has the ability to request an extension of the facility or repay the entire balance at the end of the term. At December 31, 2018, Enerplus was undrawn on the facility (December 31, 2017 –undrawn). During 2018, a fee of $ 0.4 million (2017 – $0. 5 million, 2016 – $0. 7 million) was paid to extend the facility.

Senior Notes

During 2018 and 2017, Enerplus made its first and second US$22 million principal repayments on its 2009 senior notes. During 2016, Enerplus repurchased US$267 million in outstanding senior notes at a discount, resulting in gains of $19.3 million.

52                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

The terms and rates of the Company’s outstanding senior notes are detailed below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

  

 

  

Original

  

Remaining

  

CDN$ Carrying

 

 

 

 

 

 

Coupon

 

Principal

 

Principal

 

Value

Issue Date

 

Interest Payment Dates

 

Principal Repayment

 

Rate

 

($ thousands)

 

($ thousands)

 

($ thousands)

September 3, 2014

 

March 3 and Sept 3

 

5 equal annual installments beginning September 3, 2022

 

3.79%

 

US$200,000

 

US$105,000

 

$

143,189

May 15, 2012

 

May 15 and Nov 15

 

Bullet payment on May 15, 2019

 

4.34%

 

CDN$30,000

 

CDN$30,000

 

 

30,000

May 15, 2012

 

May 15 and Nov 15

 

Bullet payment on May 15, 2022

 

4.40%

 

US$20,000

 

US$20,000

 

 

27,274

May 15, 2012

 

May 15 and Nov 15

 

5 equal annual installments beginning May 15, 2020

 

4.40%

 

US$355,000

 

US$298,000

 

 

406,383

June 18, 2009

 

June 18 and Dec 18

 

3 equal annual installments beginning June 18, 2019 - 2021

 

7.97%

 

US$225,000

 

US$66,000

 

 

90,004

 

 

 

 

 

 

 

 

Total carrying value

 

$

696,850

 

 

 

8) ASSET RETIREMENT OBLIGATION

 

 

 

 

 

 

 

($ thousands)

   

December 31, 2018

   

December 31, 2017

Balance, beginning of year

 

$

117,736

 

$

181,700

Change in estimates

 

 

16,755

 

 

13,064

Property acquisition and development activity

 

 

1,565

 

 

1,322

Divestments

 

 

(4,585)

 

 

(72,306)

Settlements

 

 

(11,263)

 

 

(12,907)

Accretion expense

 

 

5,904

 

 

6,863

Balance, end of year

 

$

126,112

 

$

117,736

 

Enerplus has estimated the present value of its asset retirement obligation to be $126.1 million at December 31, 2018 based on a total undiscounted liability of $343.9 million (December 31, 2017 – $117.7 million and $318.8 million, respectively). The asset retirement obligation was calculated using a weighted average credit-adjusted risk‑free rate of 5.59% and inflation rate of 1.8% (December 31, 2017 – 5.73% and 1.8%, respectively).  The majority of Enerplus’ asset retirement obligation expenditures are expected to be incurred between 2025 and 2055.

 

 

9) OIL AND NATURAL GAS SALES

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

2018

    

2017

    

2016

Oil and natural gas sales

 

$

1,610,899

 

$

1,141,770

 

$

882,126

Royalties (1)

 

 

(318,163)

 

 

(221,077)

 

 

(159,394)

Oil and natural gas sales, net of royalties

 

$

1,292,736

 

$

920,693

 

$

722,732

(1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss).

 

Oil and natural gas revenue by country and by product for the year ended December 31, 2018 is as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2018

 

 

Total revenue, net

 

 

 

 

 

Natural

 

 

Natural gas

 

 

 

($ thousands)

 

 

of royalties (1)

 

 

Crude oil (2)

 

 

gas (2)

 

 

liquids (2)

 

 

Other (3)

Canada

    

$

198,263

 

$

148,949

    

$

32,109

    

$

14,075

    

$

3,130

United States

 

 

1,094,473

 

 

834,146

 

 

236,825

 

 

23,502

 

 

 —

Total

 

$

1,292,736

 

$

983,095

 

$

268,934

 

$

37,577

 

$

3,130

(1)

Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss).

(2)

U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties.

(3)

Includes third party processing income.

 

Enerplus sells the majority of its production pursuant to variable-price contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under the contracts, the Company is required to deliver a fixed or variable volume of crude oil, natural gas liquids or natural gas to the contract counterparty. Revenue is recognized when a unit of production is delivered to the contract counterparty. The amount of revenue recognized is based on the agreed transaction price, and any variability in revenue relates to the Company’s ability to deliver product. As a result, revenue is allocated to the production delivered in the period.

 

Crude oil, natural gas and natural gas liquids are sold under contracts of varying terms, including multi-year contracts. Revenues are typically collected in the month following production.

ENERPLUS 2018 FINANCIAL SUMMARY                 53

 

 

      

10) GENERAL AND ADMINISTRATIVE EXPENSE

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

2018

  

2017

  

2016

General and administrative expense

 

$

49,943

 

$

50,544

 

$

59,773

Share-based compensation expense (1)

 

 

25,840

 

 

23,757

 

 

26,546

General and administrative expense

 

$

75,783

 

$

74,301

 

$

86,319

 

 

(1)

Includes cash and non-cash share-based compensation.

 

 

11) FOREIGN EXCHANGE

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

2018

    

2017

  

2016

Realized:

 

 

 

 

 

 

 

 

 

Foreign exchange (gain)/loss

 

$

523

 

$

1,495

 

$

108

Translation of U.S. dollar cash held in Canada (gain)/loss

 

 

(19,630)

 

 

10,978

 

 

 —

Unrealized:

 

 

 

 

 

 

 

 

 

Translation of U.S. dollar debt and working capital (gain)/loss

 

 

58,628

 

 

(42,623)

 

 

(40,634)

Foreign exchange (gain)/loss

 

$

39,521

 

$

(30,150)

 

$

(40,526)

 

 

12) INCOME TAXES

Enerplus’ provision for income tax is as follows:

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

2018

  

2017

  

2016

Current tax expense/(recovery)

 

 

 

 

 

 

 

 

 

Canada

 

$

(400)

 

$

(407)

 

$

(661)

United States

 

 

(26,693)

 

 

(47,550)

 

 

(1,690)

Current tax expense/(recovery)

 

 

(27,093)

 

 

(47,957)

 

 

(2,351)

Deferred tax expense/(recovery)

 

 

 

 

 

 

 

 

 

Canada

 

$

3,915

 

$

(17,127)

 

$

(23,714)

United States

 

 

126,389

 

 

147,072

 

 

(211,133)

Deferred tax expense/(recovery)

 

 

130,304

 

 

129,945

 

 

(234,847)

Income tax expense/(recovery)

 

$

103,211

 

$

81,988

 

$

(237,198)

 

The following provides a reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes:

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

2018

    

2017

    

2016

Income/(loss) before taxes

 

 

 

 

 

 

 

 

 

Canada

 

$

104,204

 

$

146,953

 

$

121,257

United States

 

 

377,286

 

 

172,033

 

 

38,961

Total income/(loss) before taxes

 

 

481,490

 

 

318,986

 

 

160,218

Canadian statutory rate

 

 

27.00%

 

 

27.00%

 

 

27.00%

Expected income tax expense/(recovery)

 

$

130,002

 

$

86,126

 

$

43,259

Impact on taxes resulting from:

 

 

 

 

 

 

 

 

 

Foreign and statutory rate differences

 

$

(23,859)

 

$

157,320

 

$

(12,826)

Share-based compensation

 

 

(18,102)

 

 

5,067

 

 

6,611

Non-taxable capital (gains)/losses

 

 

7,254

 

 

(6,337)

 

 

(6,478)

Change in valuation allowance

 

 

6,292

 

 

(162,992)

 

 

(266,896)

Other

 

 

1,624

 

 

2,804

 

 

(868)

Income tax expense/(recovery)

 

$

103,211

 

$

81,988

 

$

(237,198)

 

 

 

 

 

 

 

 

 

 

54                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

The deferred income tax asset consists of the following:

 

 

 

 

 

 

 

As at December 31 ($ thousands)

    

2018

    

2017

Deferred income tax liabilities

 

 

 

 

 

 

Property, plant and equipment

 

$

(46,284)

 

$

 —

Derivative financial instruments

 

 

(24,184)

 

 

 —

Total deferred income tax liabilities

 

 

(70,468)

 

 

 —

Deferred income tax assets

 

 

 

 

 

 

Property, plant and equipment

 

$

60,665

 

$

132,879

Tax loss carry-forwards and other credits

 

 

429,651

 

 

397,081

Capital loss carryforwards and other capital items

 

 

188,409

 

 

181,334

Asset retirement obligation

 

 

33,935

 

 

31,677

Derivative financial instruments

 

 

 —

 

 

8,795

Other assets

 

 

14,099

 

 

3,046

Deferred income tax asset before valuation allowance

 

 

726,759

 

 

754,812

Valuation allowance

 

 

(191,167)

 

 

(184,875)

Deferred income tax assets, net

 

 

535,592

 

 

569,937

Total deferred income tax asset

 

$

465,124

 

$

569,937

 

As of December 31, 2018, $27.2 million was reclassified from deferred income tax asset to income tax receivable for the AMT refund expected to be realized in 2019 (December 31, 2017 – $50.1 million).

Loss carry-forwards and tax credits available for tax reporting purposes:

 

 

 

 

 

 

As at December 31  ($ thousands)

   

2018

    

Expiration Date

Canada

 

 

 

 

 

Capital losses

 

$

1,226,000

 

Indefinite

Non-capital losses

 

 

410,000

 

2028-2038

United States

 

 

 

 

 

Net operating losses – prior to 2018

 

$

933,000

 

2030-2037

Net operating losses – 2018 and thereafter

 

 

119,000

 

Indefinite

Alternative minimum tax credits

 

 

58,000

 

Recoverable 2019-2021

 

Changes in the balance of Enerplus' unrecognized tax benefits are as follows:

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

2018

    

2017

 

2016

Balance, beginning of year

 

$

13,300

 

$

13,300

 

$

15,100

Settlements

 

 

 —

 

 

 —

 

 

(1,800)

Balance, end of year

 

$

13,300

 

$

13,300

 

$

13,300

 

If recognized, all of Enerplus’ unrecognized tax benefits as at December 31, 2018 would affect Enerplus’ effective income tax rate. It is not anticipated that the amount of unrecognized tax benefits will significantly change during the next 12 months.

A summary of the taxation years, by jurisdiction, that remain subject to examination by the taxation authorities are as follows:

 

 

 

Jurisdiction

   

Taxation Years

Canada – Federal & Provincial

 

2013-2018

United States – Federal & State

 

2015-2018

Enerplus and its subsidiaries file income tax returns primarily in Canada and the United States. Matters in dispute with the taxation authorities are ongoing and in various stages of completion.  

 

ENERPLUS 2018 FINANCIAL SUMMARY                 55

 

 

      

13) SHAREHOLDERS’ EQUITY

a) Share Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2018

 

2017

 

2016

Authorized: unlimited number of common shares

Issued: (thousands)

    

Shares

    

Amount

    

Shares

    

Amount

    

Shares

    

Amount

Balance, beginning of year

 

242,129

 

$

3,386,946

 

240,483

 

$

3,365,962

 

206,539

 

$

3,133,524

Issued for cash:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchase of common shares under Normal Course Issuer Bid

 

(5,925)

 

 

(82,596)

 

 —

 

 

 —

 

 —

 

 

 —

Stock Option Plan

 

668

 

 

9,138

 

 —

 

 

 —

 

 —

 

 

 —

Public offering

 

 —

 

 

 —

 

 —

 

 

 —

 

33,350

 

 

230,115

Share issue costs (net of tax of $2,621)

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

(7,084)

Non-cash:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Share-based compensation – settled

 

2,539

 

 

23,389

 

1,646

 

 

20,984

 

594

 

 

9,407

Stock Option Plan – exercised

 

 —

 

 

731

 

 —

 

 

 —

 

 —

 

 

 —

Balance, end of year

 

239,411

 

$

3,337,608

 

242,129

 

$

3,386,946

 

240,483

 

$

3,365,962

 

The Company is authorized to issue an unlimited number of common shares without par value.

 

For the year ended December 31, 2018, Enerplus declared dividends of $0.12 per weighted average common share totaling $29.3 million (December 31, 2017 – $0.12 per share and $ 29.0 million, December 31, 2016 – $0. 16 per share and $ 35.4 million).

 

On March 21, 2018, Enerplus announced the acceptance of its Normal Course Issuer Bid (“NCIB”) to repurchase shares through the facilities of the Toronto Stock Exchange, New York Stock Exchange and/or alternative Canadian trading systems. Pursuant to the NCIB, the Company was permitted to repurchase for cancellation up to 17,095,598 common shares over a period of twelve months commencing on March 26, 2018. All repurchases are made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess is allocated to accumulated deficit. For the year ended December 31, 2018, the Company repurchased 5,925,084 common shares under the NCIB at an average price of $13.33 per share, for total consideration of $79.0 million. Of the amount paid, $82.6 million was charged to share capital and $3.6 million was credited to accumulated deficit.

 

Subsequent to the year, and up to February 20, 2019, the Company repurchased an additional 586,953 common shares under the NCIB at an average price of $11.40 per share, for consideration of $6.7 million. The Company also received approval from the Board of Directors to renew the NCIB upon expiry of the existing term on March 25, 2019, subject to approval by the TSX. The proposed renewal will be for 7% of public float (within the meaning under the TSX rules) consistent with the current bid.

 

b) Share-based Compensation

The following table summarizes Enerplus' share-based compensation expense, which is included in General and Administrative expense on the Consolidated Statements of Income/(Loss):

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

2018

  

2017

   

2016

Cash:

 

 

 

 

 

 

 

 

 

Long-term incentive plans expense

 

$

133

 

$

997

 

$

3,114

Non-Cash:

 

 

 

 

 

 

 

 

 

Long-term incentive plans expense

 

 

25,917

 

 

22,576

 

 

26,951

Equity swap (gain)/loss

 

 

(210)

 

 

184

 

 

(3,582)

Stock option plan expense

 

 

 —

 

 

 —

 

 

63

Share-based compensation expense

 

$

25,840

 

$

23,757

 

$

26,546

 

 

 

 

 

 

 

 

 

 

 

56                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

i) Long-term Incentive (“LTI”) Plans

The following table summarizes the Performance Share Unit (“PSU”), Restricted Share Unit (“RSU”) and Deferred Share Unit (“DSU”) activity for the twelve months ended December 31, 2018:

 

 

 

 

 

 

 

 

 

For the year ended December 31, 2018

 

Cash-settled LTI Plans

 

Equity-settled LTI Plans

 

Total

(thousands of units)

    

                            DSU

   

PSU (1)

    

      RSU

   

 

Balance, beginning of year

 

368

 

2,713

 

2,109

 

5,190

Granted

 

78

 

735

 

809

 

1,622

Vested

 

(55)

 

(2,071)

 

(1,080)

 

(3,206)

Forfeited

 

 —

 

(6)

 

(85)

 

(91)

Balance, end of year

 

391

 

1,371

 

1,753

 

3,515

(1) Based on underlying awards before any effect of the performance multiplier.

 

Cash-settled LTI Plans

For the year ended December 31, 2018, the Company made cash payments of $0. 5 million related to its cash-settled plans (2017 – $0.1 million, 2016 – $2.7 million).  

The 2016 PSU’s which vested in December 2018 were cash settled in January 2019, resulting in $30.6 million being recorded to Accounts Payable and Paid-in Capital on the Consolidated Balance Sheets at December 31, 2018.

 

As of December 31, 2018, a liability of $4. 1 million (December 31, 2017 – $ 4.5 million) with respect to the DSU plan has been recorded to Accounts Payable on the Consolidated Balance Sheets.

Equity-settled LTI Plans

The following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms.

 

 

 

 

 

 

 

 

 

 

At December 31, 2018 ($ thousands, except for years)

    

PSU (1)

    

RSU

    

Total

Cumulative recognized share-based compensation expense

 

$

17,042

 

$

12,765

 

$

29,807

Unrecognized share-based compensation expense 

 

 

15,131

 

 

5,429

 

 

20,560

Fair value

 

$

32,173

 

$

18,194

 

$

50,367

Weighted-average remaining contractual term (years)

 

 

1.8

 

 

1.4

 

 

 

(1) Includes estimated performance multipliers.

ii) Stock Option Plan

At December 31, 2018, all stock options are fully vested and all non-cash share-based compensation expense has been fully recognized.

The following table summarizes the stock option plan activity for the year ended December 31, 2018:

 

 

 

 

 

 

 

    

Number of Options

    

Weighted Average

Year ended December 31, 2018

 

(thousands)

 

Exercise Price

Options outstanding, beginning of year

 

5,486

 

$

18.25

Exercised

 

(668)

 

 

13.66

Forfeited

 

(49)

 

 

21.17

Expired

 

(638)

 

 

30.20

Options outstanding and exercisable, end of year

 

4,131

 

$

17.12

 

At December 31, 2018, 4,130,921 options were exercisable at a weighted average exercise price of $17.12 with a weighted average remaining contractual term of 0.8 years, giving an aggregate intrinsic value of nil (December 31, 2017 – nil, December 31, 2016 – nil). The intrinsic value of options exercised during the year ended December 31, 2018 was $1.9 million (December 31, 2017 – nil, December 31, 2016 – nil).

ENERPLUS 2018 FINANCIAL SUMMARY                 57

 

 

      

c) Basic and Diluted Net Income/(Loss) Per Share

Net income/(loss) per share has been determined as follows:

 

 

 

 

 

 

 

 

 

 

(thousands, except per share amounts)

   

2018

 

2017

 

2016

Net income/(loss)

 

$

378,279

 

$

236,998

 

$

397,416

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding – Basic

 

 

244,076

 

 

241,929

 

 

226,530

Dilutive impact of share-based compensation

 

 

3,185

 

 

5,945

 

 

4,763

Weighted average shares outstanding – Diluted

 

 

247,261

 

 

247,874

 

 

231,293

Net income/(loss) per share

 

 

 

 

 

 

 

 

 

Basic

 

$

1.55

 

$

0.98

 

$

1.75

 Diluted

 

$

1.53

 

$

0.96

 

$

1.72

 

 

14) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At December 31, 2018, senior notes had a carrying value of $696.9 million and a fair value of $695.4 million (December 31, 2017 – $672.4 million and $687.2 million, respectively).

There were no transfers between fair value hierarchy levels during the year.

b) Derivative Financial Instruments

The derivative financial assets and liabilities on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value.

The following tables summarize the change in fair value for the respective years:

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

 

    

 

 

    

 

 

    

Income

Gain/(Loss)  ($ thousands)

 

2018

 

2017

 

2016

 

Statement Presentation

Equity Swaps

 

$

210

 

$

(184)

 

$

3,582

 

G&A expense

Electricity Swaps

 

 

 —

 

 

639

 

 

1,135

 

Operating expense

Commodity Derivative Instruments:

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

114,822

 

 

(5,445)

 

 

(96,238)

 

Commodity derivative

Gas

 

 

9,234

 

 

11,174

 

 

(13,505)

 

instruments

Total Unrealized Gain/(Loss)

 

$

124,266

 

$

6,184

 

$

(105,026)

 

 

 

The following table summarizes the effect of Enerplus’ commodity derivative instruments on the Consolidated Statements of Income/(Loss):

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

2018

   

2017

    

2016

Change in fair value gain/(loss)

 

$

124,056

 

$

5,729

 

$

(109,743)

Net realized cash gain/(loss)

 

 

(35,824)

 

 

8,581

 

 

80,346

Commodity derivative instruments gain/(loss)

 

$

88,232

 

$

14,310

 

$

(29,397)

 

The following table summarizes the fair values at the respective year ends:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2018

 

December 31, 2017

 

 

Assets

 

Liabilities

 

 

Assets

 

 

Liabilities

($ thousands)

    

Current

    

Long-term

    

Current

    

 

Current

 

 

Current

    

Long-term

Equity Swaps

 

$

 —

 

$

 —

 

$

1,909

 

$

 —

 

$

2,119

 

$

 —

Commodity Derivative Instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

48,314

 

 

32,220

 

 

 —

 

 

2,142

 

 

26,523

 

 

9,907

Gas

 

 

10,944

 

 

 —

 

 

 —

 

 

1,710

 

 

 —

 

 

 —

Total

 

$

59,258

 

$

32,220

 

$

1,909

 

$

3,852

 

$

28,642

 

$

9,907

58                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

c) Risk Management

In the normal course of operations, Enerplus is exposed to various market risks, including commodity prices, foreign exchange, interest rates and equity prices, credit risk and liquidity risk.

i) Market Risk

Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.

Commodity Price Risk:

Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes.

The following tables summarize Enerplus’ price risk management positions at February 20, 2019:

Crude Oil Instruments:

 

 

 

 

 

Instrument Type (1)(2)

    

bbls/day

    

US$/bbl

 

 

 

 

 

Jan 1, 2019 – Mar 31, 2019

 

  

 

  

WTI Swap

 

3,000

 

53.73

WTI Purchased Put

 

17,000

 

54.12

WTI Sold Call

 

17,000

 

64.12

WTI Sold Put

 

17,000

 

44.28

WCS Differential Swap

 

1,500

 

(14.17)

 

 

 

 

 

Apr 1, 2019 – Jun 30, 2019

 

 

 

 

WTI Purchased Put

 

23,500

 

54.59

WTI Sold Call

 

23,500

 

65.52

WTI Sold Put

 

23,500

 

44.50

WCS Differential Swap

 

1,500

 

(14.83)

WTI - Brent Swap

 

2,700

 

(8.10)

 

 

 

 

 

Jul 1, 2019 – Sep 30, 2019

 

 

 

 

WTI Purchased Put

 

24,500

 

54.81

WTI Sold Call

 

24,500

 

65.95

WTI Sold Put

 

24,500

 

44.64

WCS Differential Swap

 

1,500

 

(14.83)

WTI - Brent Swap

 

2,700

 

(8.10)

 

 

 

 

 

Oct 1, 2019 – Dec 31, 2019

 

 

 

 

WTI Purchased Put

 

24,500

 

54.81

WTI Sold Call

 

24,500

 

65.99

WTI Sold Put

 

24,500

 

44.64

WCS Differential Swap

 

1,500

 

(14.83)

WTI - Brent Swap

 

2,700

 

(8.10)

 

 

 

 

 

Jan 1, 2020 – Dec 31, 2020

 

 

 

 

WTI Purchased Put

 

16,000

 

57.50

WTI Sold Call

 

16,000

 

72.50

WTI Sold Put

 

16,000

 

46.88

WTI - Brent Swap

 

4,400

 

(8.03)

(1)

Transactions with a common term have been aggregated and presented as the weighted average price/bbl before premiums.

(2)

The total average deferred premium on three way collars is US$1.61/bbl from January 1, 2019 to December 31, 2020.

ENERPLUS 2018 FINANCIAL SUMMARY                 59

 

 

      

Natural Gas Instruments:

 

 

 

 

 

 

Instrument Type (1)

    

MMcf/day

    

US$/Mcf

 

 

 

 

 

Jan 1, 2019 – Mar 31, 2019

 

 

 

 

NYMEX Swap

 

50.0

 

4.23

NYMEX Purchased Put

 

50.0

 

3.80

NYMEX Sold Call

 

50.0

 

6.01

 

 

 

 

 

Apr 1, 2019 – Oct 31, 2019

 

 

 

 

NYMEX Swap

 

70.0

 

2.85

(1)

Transactions with a common term have been aggregated and presented as the weighted average price/Mcf.

Enerplus has physical sales contracts in place for approximately 16,000 bbls/day of 2019 Bakken production with fixed differentials averaging approximately US$3.00/bbl below WTI.

Foreign Exchange Risk:

Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, U.S. dollar denominated senior notes, cash deposits and working capital. Additionally, Enerplus’ crude oil sales and a significant portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At December 31, 2018, Enerplus did not have any foreign exchange derivatives outstanding.

Interest Rate Risk:

At December 31, 2018, all of Enerplus’ debt was based on fixed interest rates, and Enerplus did not have any interest rate derivatives outstanding.

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its long‑term incentive plans detailed in Note 13. Enerplus has entered into various equity swaps maturing in 2019 and has effectively fixed the future settlement cost on 195,000 shares at a weighted average price of $20.60 per share.

ii) Credit Risk

Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables.

Enerplus mitigates credit risk through credit management techniques, including conducting financial assessments to establish and monitor counterparties’ credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis.

Enerplus’ maximum credit exposure at the balance sheet date consists of the carrying amount of its non‑derivative financial assets and the fair value of its derivative financial assets. At December 31, 2018, approximately 80% of Enerplus’ marketing receivables were with companies considered investment grade.

Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts off future payments or seeking other remedies including legal action. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If Enerplus subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account. Enerplus’ allowance for doubtful accounts balance at December 31, 2018 was $3.9 million (December 31, 2017 – $3. 5  million).

iii)   Liquidity Risk & Capital Management

Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt (net of cash and cash equivalents) and shareholders’ capital. Enerplus’ objective is to provide adequate short and longer term liquidity while maintaining a flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas assets and planned investment opportunities.

Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, share repurchases, access to capital markets, as well as acquisition and divestment activity.

60                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

At December 31, 2018, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.

15) COMMITMENTS AND CONTINGENCIES

a) Commitments

Enerplus has the following minimum annual commitments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Minimum Annual Commitment Each Year

 

 

 

($ thousands)

 

        Total

 

2019

 

2020

 

2021

 

2022

 

2023

 

Thereafter

Senior notes (1)

$

 

696,850

 

$

60,001

 

$

111,278

 

$

111,278

 

$

109,914

 

$

108,551

 

$

195,828

Transportation commitments (2)

 

 

367,646

   

 

36,817

   

 

37,951

   

 

34,102

   

 

31,410

   

 

30,317

   

 

197,049

Processing commitments

 

 

16,174

 

 

3,506

 

 

3,174

 

 

1,519

 

 

1,519

 

 

1,519

 

 

4,937

Drilling and completions

 

 

51,433

 

 

20,005

 

 

20,005

 

 

11,423

 

 

 —

 

 

 —

 

 

 —

Office lease commitments

 

 

73,746

 

 

9,421

 

 

10,662

 

 

11,146

 

 

11,328

 

 

11,453

 

 

19,736

Sublease recoveries

 

 

(15,405)

 

 

(3,151)

 

 

(3,401)

 

 

(3,198)

 

 

(2,434)

 

 

(1,720)

 

 

(1,501)

Net office lease commitments (5)

 

 

58,341

 

 

6,270

 

 

7,261

 

 

7,948

 

 

8,894

 

 

9,733

 

 

18,235

Total commitments (3)(4)

$

 

1,190,444

 

$

126,599

 

$

179,669

 

$

166,270

 

$

151,737

 

$

150,120

 

$

416,049

(1)

Interest payments have not been included.

(2)

Includes additional firm transportation commitments executed subsequent to year-end.

(3)

Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

(4)

US$ commitments have been converted to CDN$ using the December 31, 2018 foreign exchange rate of 1. 3637 .

(5)

Net office lease payments in 2018 were $8.0 million (2017 – $ 9.7 million, 2016 – $10. 5 million).

b) Contingencies

Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements.  In instances where the Company determines that a loss is probable and the amount can be reasonably estimated, an accrual is recorded.

16) GEOGRAPHICAL INFORMATION

 

 

 

 

 

 

 

 

 

 

As at and for the year ended December 31, 2018 ($ thousands)

   

Canada

    

U.S.

    

Total

Oil and natural gas sales, net of royalties

 

$

198,263

 

$

1,094,473

 

$

1,292,736

Depletion, depreciation and accretion

 

 

58,333

 

 

245,941

 

 

304,274

Property, plant and equipment

 

 

262,159

 

 

1,044,912

 

 

1,307,071

Goodwill

 

 

451,121

 

 

203,678

 

 

654,799

Long term income tax receivable

 

 

 —

 

 

27,195

 

 

27,195

 

 

 

 

 

 

 

 

 

 

 

As at and for the year ended December 31, 2017 ($ thousands)

    

Canada

    

U.S.

    

Total

Oil and natural gas sales, net of royalties

 

$

227,031

 

$

693,662

 

$

920,693

Depletion, depreciation and accretion

 

 

89,936

 

 

160,838

 

 

250,774

Property, plant and equipment

 

 

246,604

 

 

653,427

 

 

900,031

Goodwill

 

 

451,121

 

 

187,757

 

 

638,878

Long term income tax receivable

 

 

 —

 

 

50,108

 

 

50,108

 

 

 

 

 

 

 

 

 

 

 

 

As at and for the year ended December 31, 2016 ($ thousands)

    

Canada

    

U.S.

    

Total

Oil and natural gas sales, net of royalties

 

$

233,391

 

$

489,341

 

$

722,732

Depletion, depreciation and accretion

 

 

126,062

 

 

202,902

 

 

328,964

Property, plant and equipment

 

 

304,048

 

 

434,382

 

 

738,430

Goodwill

 

 

451,121

 

 

200,542

 

 

651,663

Long term income tax receivable

 

 

 —

 

 

 —

 

 

 —

 

ENERPLUS 2018 FINANCIAL SUMMARY                 61

 

 

      

17) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non‑Cash Operating Working Capital

 

 

 

 

 

 

 

 

 

 

($ thousands)

 

December 31, 2018

 

December 31, 2017

 

December 31, 2016

Accounts receivable

 

$

(45,385)

 

$

(66,860)

 

$

16,982

Other current assets

 

 

(3,026)

 

 

(154)

 

 

2,154

Accounts payable

 

 

44,952

 

 

31,982

 

 

(4,061)

 

 

$

(3,459)

 

$

(35,032)

 

$

15,075

 

b) Changes in Other Non-Cash Working Capital

 

 

 

 

 

 

 

 

 

 

($ thousands)

    

December 31, 2018

    

December 31, 2017

    

December 31, 2016

Non-cash financing activities (1)

 

$

(26)

 

$

16

 

$

(3,791)

Non-cash investing activities (2)

 

$

(3,753)

 

$

1,523

 

$

(49,472)

(1)

Relates to changes in dividends payable and included in dividends on the Consolidated Statements of Cash Flows.

(2)

Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Consolidated Statements of Cash Flows.

 

c) Other

 

 

 

 

 

 

 

 

 

 

($ thousands)

 

December 31, 2018

 

December 31, 2017

    

December 31, 2016

Income taxes paid/(received)

 

$

(481)

 

$

2,640

 

$

(21,244)

Interest paid

 

$

36,161

 

$

38,149

 

$

48,545

 

 

 

 

 

62                 ENERPLUS 2018 FINANCIAL SUMMARY

 

 

      

 

 

PICTURE 2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contents

1

   

Financial Summary

3

 

Highlights

4

 

Management’s Discussion and Analysis

37

 

Financial Statements

63

 

Five Year Detailed Statistical Review

65

 

Supplemental Information

66

 

Abbreviations and Definitions

69

 

Board of Directors

70

 

Officers

71

 

Corporate Information

 

 

 

 

 

 

         2018 FINANCIAL SUMMARY

    

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Twelve months ended

SELECTED FINANCIAL RESULTS

December 31, 

 

December 31, 

 

    

2018

    

2017

 

    

2018

    

2017

Financial (000’s)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

$

249,315

 

$

15,272

 

 

$

378,279

 

$

236,998

Cash Flow from Operating Activities

 

 

221,619

 

 

135,332

 

 

 

738,784

 

 

476,125

Adjusted Funds Flow (4)

 

 

214,285

 

 

199,559

 

 

 

753,506

 

 

524,064

Dividends to Shareholders - Declared

 

 

7,234

 

 

7,264

 

 

 

29,256

 

 

29,033

Total Debt Net of Cash (4)

 

 

333,523

 

 

325,831

 

 

 

333,523

 

 

325,831

Capital Spending

 

 

72,058

 

 

116,827

 

 

 

593,876

 

 

458,015

Property and Land Acquisitions

 

 

9,474

 

 

3,805

 

 

 

25,840

 

 

13,276

Property Divestments

 

 

886

 

 

(1,385)

 

 

 

6,912

 

 

56,196

Net Debt to Adjusted Funds Flow Ratio (4)

 

 

0.4x

 

 

0.6x

 

 

 

0.4x

 

 

0.6x

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial per Weighted Average Shares Outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income - Basic

 

$

1.03

 

$

0.06

 

 

$

1.55

 

$

0.98

Net Income - Diluted

 

 

1.02

 

 

0.06

 

 

 

1.53

 

 

0.96

Weighted Average Number of Shares Outstanding (000’s) - Basic

 

 

242,344

 

 

242,129

 

 

 

244,076

 

 

241,929

Weighted Average Number of Shares Outstanding (000’s) - Diluted

 

 

245,242

 

 

248,122

 

 

 

247,261

 

 

247,874

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected Financial Results per BOE (1)(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil & Natural Gas Sales (3)

 

$

45.43

 

$

41.72

 

 

$

47.35

 

$

36.93

Royalties and Production Taxes

 

 

(11.58)

 

 

(10.65)

 

 

 

(11.92)

 

 

(8.91)

Commodity Derivative Instruments

 

 

(0.31)

 

 

(0.39)

 

 

 

(1.05)

 

 

0.28

Cash Operating Expenses

 

 

(6.99)

 

 

(6.42)

 

 

 

(7.00)

 

 

(6.39)

Transportation Costs

 

 

(3.71)

 

 

(3.20)

 

 

 

(3.63)

 

 

(3.60)

General and Administrative Expenses

 

 

(1.40)

 

 

(1.55)

 

 

 

(1.47)

 

 

(1.63)

Cash Share-Based Compensation

 

 

0.23

 

 

(0.01)

 

 

 

(0.01)

 

 

(0.03)

Interest, Foreign Exchange and Other Expenses

 

 

(0.90)

 

 

(1.17)

 

 

 

(0.92)

 

 

(1.24)

Current Income Tax Recovery

 

 

3.03

 

 

6.15

 

 

 

0.80

 

 

1.55

Adjusted Funds Flow (4)

 

$

23.80

 

$

24.48

 

 

$

22.15

 

$

16.96

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Twelve months ended

SELECTED OPERATING RESULTS

December 31, 

 

December 31, 

 

    

2018

    

2017

 

    

2018

    

2017

Average Daily Production (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil (bbls/day)

 

 

49,968

 

 

42,374

 

 

 

45,424

 

 

36,935

Natural Gas Liquids (bbls/day)

 

 

4,483

 

 

4,448

 

 

 

4,486

 

 

3,858

Natural Gas (Mcf/day)

 

 

260,453

 

 

250,607

 

 

 

259,837

 

 

263,506

Total (BOE/day)

 

 

97,860

 

 

88,590

 

 

 

93,216

 

 

84,711

 

 

 

 

 

 

 

 

 

 

 

 

 

 

% Crude Oil and Natural Gas Liquids

 

 

56%

 

 

53%

 

 

 

54%

 

 

48%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Selling Price (2)(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil (per bbl)

 

$

64.18

 

$

65.91

 

 

$

74.59

 

$

58.69

Natural Gas Liquids (per bbl)

 

 

26.72

 

 

32.26

 

 

 

28.31

 

 

30.01

Natural Gas (per Mcf)

 

 

4.28

 

 

3.03

 

 

 

3.42

 

 

3.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Wells Drilled

 

 

12

 

 

7

 

 

 

61

 

 

46

(1)

Non‑cash amounts have been excluded.

(2)

Based on Company interest production volumes. See “Basis of Presentation” section in the following MD&A.

(3)

Before transportation costs, royalties and commodity derivative instruments.

(4)

These non‑GAAP measures may not be directly comparable to similar measures presented by other entities. See “Non‑GAAP Measures” section in the following MD&A.

 

ENERPLUS 2018 FINANCIAL SUMMARY              1

 

 

         

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Twelve months ended

 

December 31, 

 

December 31, 

Average Benchmark Pricing

    

2018

 

2017

 

 

2018

 

2017

WTI crude oil (US$/bbl)

 

$

58.81

 

$

55.40

 

 

$

64.77

 

$

50.95

Brent (ICE) crude oil (US$/bbl)

 

 

68.08

 

 

61.54

 

 

 

71.53

 

 

54.83

NYMEX natural gas – last day (US$/Mcf)

 

 

3.64

 

 

2.93

 

 

 

3.09

 

 

3.11

AECO natural gas – monthly index (CDN$/Mcf)

 

 

1.90

 

 

1.96

 

 

 

1.53

 

 

2.43

US/CDN average exchange rate

 

 

1.32

 

 

1.27

 

 

 

1.30

 

 

1.30

 

 

 

 

 

 

 

 

Share Trading Summary

    

CDN (1)  – ERF

    

U.S. (2)  – ERF

For the twelve months ended December 31, 2018

 

(CDN$)

 

(US$)

High

 

$

18.04

 

$

13.87

Low

 

$

9.65

 

$

6.84

Close

 

$

10.62

 

$

7.76

(1)

TSX and other Canadian trading data combined.

(2)

NYSE and other U.S. trading data combined.

 

 

 

 

 

 

2018 Dividends per Share

 

CDN$

 

US$ (1)

First Quarter Total

$

0.03

$

0.02

Second Quarter Total

$

0.03

$

0.02

Third Quarter Total

$

0.03

$

0.02

Fourth Quarter Total

$

0.03

$

0.02

Total Year to Date

$

0.12

$

0.08

(1)

CDN$ dividends converted at the relevant foreign exchange rate on the payment date .

 

2               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         2018 HIGHLIGHTS

Financial and Operational Highlights

·

Fourth quarter 2018 production was at the high-end of the Company’s guidance range and modestly higher than the prior quarter. Total fourth quarter production averaged 97,860 BOE per day, including oil and natural gas liquids production of 54,451 barrels per day (92% oil).

·

Full year 2018 production was also at the high-end of the Company’s guidance range, averaging 93,216 BOE per day, including 49,910 barrels per day of crude oil and natural gas liquids (91% oil). Year-over-year, the Company’s 2018 production increased by 10%, with liquids production increasing by 22%. This growth was largely driven by North Dakota production which increased by 42%.

·

Higher realized commodity prices and increased production volumes resulted in significant increases to cash flow from operating activities and adjusted funds flow for 2018 compared to 2017. 

o

Fourth quarter cash flow from operating activities increased to $221.6 million from $216.1 million in the third quarter. Full year 2018 cash flow from operating activities was $738.8 million, 55% higher than 2017.

o

Fourth quarter adjusted funds flow increased to $214.3 million from $210.4 million in the third quarter. Fourth quarter adjusted funds flow benefited from a $27.2 million Alternative Minimum Tax (“AMT”) refund expected to be realized in 2019. Enerplus expects to realize the remaining $27.2 million in AMT refund in 2020 and 2021. Full year 2018 adjusted funds flow was $753.5 million, 44% higher than 2017.

·

Fourth quarter net income was $249.3 million ($1.03 per share) compared to $86.9 million ($0.35 per share) in the prior quarter. Full year 2018 net income was $378.3 million ($1.55 per share) compared to $237.0 million ($0.98 per share) in 2017.

·

Fourth quarter adjusted net income was $102.2 million ($0.42 per share) compared to $97.3 million ($0.40 per share) in the prior quarter. Full year 2018 adjusted net income was $344.8 million ($1.41 per share) compared to $132.2 million ($0.55 per share) in 2017.

·

Capital spending was $72.1 million in the fourth quarter of 2018, bringing full year 2018 capital spending to $593.9 million, in-line with the Company’s $585 million 2018 budget.

·

Enerplus remains in a strong financial position. The Company’s net debt at December 31, 2018 was $333.5 million, comprised of $696.8 million of senior notes less $363.3 million in cash. At December 31, 2018, Enerplus was undrawn on its $800 million bank credit facility and had a net debt to adjusted funds flow ratio of 0.4 times.

·

During 2018 Enerplus repurchased 5,925,084 common shares at an average share price of $13.33 and a cost of $79.0 million.

 

Reserves Highlights

·

Replaced 194% of 2018 production, adding 65.7 MMBOE (51% oil) of 2P reserves from development activities (including revisions and economic factors).

·

Material reserves growth was realized in North Dakota and the Marcellus. The Company replaced 244% of 2018 North Dakota production, adding 35.1 MMBOE of 2P reserves and 247% of 2018 Marcellus production, adding 187.4 Bcf of 2P reserves (including revisions and economic factors).

·

Finding and development (“F&D”) costs were $13.08 per BOE for proved developed producing (“PDP”) reserves, $16.69 per BOE for proved reserves, and $13.74 per BOE for 2P reserves, including future development costs (“FDC”).

·

Three-year average F&D costs were $10.17 per BOE for PDP reserves, $10.27 per BOE for proved reserves, and $10.04 per BOE for 2P reserves, including FDC.

·

Finding, development and acquisition (“FD&A”) costs were $17.42 per BOE for proved reserves and $14.37 per BOE for 2P reserves, including FDC.

·

Three-year average FD&A costs were $7.55 per BOE for proved reserves and $8.26 per BOE for 2P reserves, including FDC.

·

Total 2P reserves were 427.7 MMBOE at year-end 2018, representing an 8% increase from year-end 2017.

·

2P reserves were comprised of 49% crude oil, 5% natural gas liquids, and 46% natural gas at year-end 2018.

·

Proved developed producing reserves and total proved reserves represent 46% and 70% of 2P reserves, respectively.

 

 

 

 

ENERPLUS 2018 FINANCIAL SUMMARY              3

 

 

         MD&A

Exhibit 99.3

Management’s Discussion and Analysis (“MD&A”)

The following discussion and analysis of financial results is dated February 21, 2019 and is to be read in conjunction with the audited Consolidated Financial Statements (the “Financial Statements”) of Enerplus Corporation (“Enerplus” or the “Company”), as at December 31, 2018 and 2017 and for the years ended December 31, 2018, 2017 and 2016.

The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under “Forward‑Looking Information and Statements” for further information. The following MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America (“U.S. GAAP”). See “Non‑GAAP Measures” at the end of this MD&A for further information.

BASIS OF PRESENTATION

The Financial Statements and notes have been prepared in accordance with U.S. GAAP. All amounts are stated in Canadian dollars unless otherwise specified and all note references relate to the notes included with the Financial Statements. Certain prior period amounts have been restated to conform with current period presentation.

Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE and oil and natural gas liquids (“NGL”) have been converted to thousand cubic feet of gas equivalent (“Mcfe”) based on 0.167 bbl:1 Mcfe. The BOE and Mcfe rates are based on an energy equivalent conversion method primarily applicable at the burner tip and do not represent a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. All production volumes are presented on a Company interest basis, being the Company’s working interest share before deduction of any royalties paid to others, plus the Company’s royalty interests, unless otherwise stated. Company interest is not a term defined in Canadian National Instrument 51‑101– Standards of Disclosure for Oil and Gas Activities (“NI 51‑101”) and may not be comparable to information produced by other entities. All reserves information presented herein has been prepared in accordance with NI 51-101 and is presented at December 31, 2018 unless otherwise stated.

In accordance with U.S. GAAP, oil and natural gas sales are presented net of royalties in the Financial Statements. Under International Financial Reporting Standards, industry standard is to present oil and natural gas sales before deduction of royalties and as such this MD&A presents production, oil and natural gas sales, and BOE measures before deduction of royalties to remain comparable with our Canadian peers.

The following table provides a reconciliation of our production volumes:

 

 

 

 

 

 

 

 

 

Year ended December 31, 

Average Daily Production Volumes

2018
2017
2016

Company interest production volumes

 

 

 

 

 

 

Crude oil (bbls/day)

 

45,424

 

36,935

 

38,353

Natural gas liquids (bbls/day)

 

4,486

 

3,858

 

4,903

Natural gas (Mcf/day)

 

259,837

 

263,506

 

299,214

Company interest production volumes (BOE/day)

 

93,216

 

84,711

 

93,125

 

 

 

 

 

 

 

Royalty volumes

 

 

 

 

 

 

Crude oil (bbls/day)

 

9,054

 

7,531

 

7,198

Natural gas liquids (bbls/day)

 

951

 

777

 

932

Natural gas (Mcf/day)

 

48,923

 

47,722

 

50,270

Royalty volumes (BOE/day)

 

18,159

 

16,262

 

16,508

 

 

 

 

 

 

 

Net production volumes

 

 

 

 

 

 

Crude oil (bbls/day)

 

36,370

 

29,404

 

31,155

Natural gas liquids (bbls/day)

 

3,535

 

3,081

 

3,971

Natural gas (Mcf/day)

 

210,914

 

215,784

 

248,944

Net production volumes (BOE/day)

 

75,057

 

68,449

 

76,617

 

 

 

 

 

4               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

2018 FOURTH QUARTER OVERVIEW

Fourth quarter production averaged 97,860 BOE/day, which was higher than our third quarter production of 96,861 BOE/day. Crude oil and natural gas liquids production increased by 2% to 54,451 bbls/day compared to the third quarter and was at the high end of our fourth quarter liquids production guidance range of 53,500 – 54,500 bbls/day. Our fourth quarter capital spending of $72.1 million was largely focused on drilling in North Dakota in preparation for the 2019 capital program.

 

We reported net income of $249.3 million in the fourth quarter compared to net income of $86.9 million in the third quarter. The increase is primarily the result of a $253.7 million gain on commodity derivative instruments compared to a $54.1 million loss in the third quarter of 2018 due to crude oil prices falling below the swap and purchased put levels on our three-way collars. 

Fourth quarter cash flow from operating activities and adjusted funds flow increased to $221.6 million and $214.3 million, respectively, from $216.1 million and $210.4 million, respectively, in the third quarter. The increases were due to higher realized natural gas prices in the Marcellus, offset by a decrease in crude oil revenue.  Adjusted funds flow in the fourth quarter benefited from a $27.2 million Alternative Minimum Tax (“AMT”) refund, expected to be realized in 2019.

During the fourth quarter, we had $142.2 million in free cash flow, enabling our repurchase of 5.4 million common shares for $70.6 million, bringing total repurchases in 2018 to $79.0 million (5.9 million shares), and further enhancing our per share growth and the return of capital to shareholders.

 

Selected Fourth Quarter Canadian and U.S. Financial Results

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

 

Three months ended

 

 

December 31, 2018

 

 

December 31, 2017

(millions, except per unit amounts)

   

Canada

    

U.S.

    

Total

 

    

Canada

    

U.S.

    

Total

Average Daily Production Volumes (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (bbls/day)

 

 

9,237

 

 

40,731

 

 

49,968

 

 

 

9,478

 

 

32,896

 

 

42,374

Natural gas liquids (bbls/day)

 

 

956

 

 

3,527

 

 

4,483

 

 

 

1,198

 

 

3,250

 

 

4,448

Natural gas (Mcf/day)

 

 

23,357

 

 

237,096

 

 

260,453

 

 

 

37,265

 

 

213,342

 

 

250,607

Total average daily production (BOE/day)

 

 

14,086

 

 

83,774

 

 

97,860

 

 

 

16,887

 

 

71,703

 

 

88,590

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pricing (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (per bbl)

 

$

33.76

 

$

71.07

 

$

64.18

 

 

$

57.05

 

$

68.46

 

$

65.91

Natural gas liquids (per bbl)

 

 

39.69

 

 

23.20

 

 

26.72

 

 

 

44.07

 

 

27.91

 

 

32.26

Natural gas (per Mcf)

 

 

3.74

 

 

4.33

 

 

4.28

 

 

 

3.01

 

 

3.04

 

 

3.03

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital spending

 

$

13.5

 

$

58.6

 

$

72.1

 

 

$

10.9

 

$

105.9

 

$

116.8

Acquisitions

 

 

1.2

 

 

8.3

 

 

9.5

 

 

 

1.1

 

 

2.7

 

 

3.8

Divestments

 

 

0.9

 

 

(1.8)

 

 

(0.9)

 

 

 

0.9

 

 

0.5

 

 

1.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Netback (3) Before Hedging

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

$

40.9

 

$

368.3

 

$

409.2

 

 

$

64.9

 

$

275.2

 

$

340.1

Royalties

 

 

(5.4)

 

 

(77.0)

 

 

(82.4)

 

 

 

(13.9)

 

 

(55.1)

 

 

(69.0)

Production taxes

 

 

(0.4)

 

 

(21.5)

 

 

(21.9)

 

 

 

(0.7)

 

 

(17.1)

 

 

(17.8)

Cash operating expenses

 

 

(17.8)

 

 

(45.1)

 

 

(62.9)

 

 

 

(18.2)

 

 

(34.1)

 

 

(52.3)

Transportation costs

 

 

(2.6)

 

 

(30.8)

 

 

(33.4)

 

 

 

(2.9)

 

 

(23.3)

 

 

(26.2)

Netback before hedging

 

$

14.7

 

$

193.9

 

$

208.6

 

 

$

29.2

 

$

145.6

 

$

174.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative instruments loss/(gain)

 

$

(253.7)

 

$

 —

 

$

(253.7)

 

 

$

41.0

 

$

 —

 

$

41.0

General and administrative expense (4)

 

 

11.6

 

 

7.5

 

 

19.1

 

 

 

13.9

 

 

5.8

 

 

19.7

Current income tax recovery

 

 

 —

 

 

(27.4)

 

 

(27.4)

 

 

 

 —

 

 

(50.2)

 

 

(50.2)

(1) Company interest volumes.

(2) Before transportation costs, royalties and the effects of commodity derivative instruments.

(3) See “Non‑GAAP Measures” section in this MD&A.

(4) Includes share‑based compensation.

 

ENERPLUS 2018 FINANCIAL SUMMARY              5

 

 

         

Comparing the fourth quarter of 2018 with the same period in 2017:

·

Average daily production was 97,860 BOE/day, an increase of 10% from 88,590 BOE/day, primarily due to a 24% increase in U.S. crude oil production as a result of strong well performance and a larger capital spending program in North Dakota in 2018.

·

Our crude oil and natural gas liquids production accounted for 56% of our total production mix in the fourth quarter of 2018, an increase from 53% in 2017.

·

Capital spending decreased to $72.1 million compared to $116.8 million in the fourth quarter of 2017 due to the timing of our 2018 capital program and limited completions activity in the fourth quarter. The majority of our capital investment in the fourth quarter was focused on drilling our U.S. crude oil properties, with spending of $51.7 million.

·

Operating expenses increased to $62.9 million ($6.99/BOE) compared to $52.1 million ($6.39/BOE) in the fourth quarter of 2017 as a result of an increased weighting of crude oil and liquids production with higher associated operating cost metrics.

·

Cash general and administrative (“G&A”) expenses were unchanged but improved on a per BOE basis from $12.6 million ($1.40/BOE) compared to $12.6 million ($1.55/BOE) in 2017 with increased production volumes.

·

During the fourth quarter of 2018, our Bakken crude oil price differential widened to US$5.60/bbl below WTI compared to US$1.61/bbl below WTI for the same period in 2017, as a result of significant refinery maintenance reducing demand in the region. Our Marcellus natural gas differential narrowed in the fourth quarter to US$0.34/Mcf below NYMEX compared to US$0.81/Mcf below NYMEX in 2017, due to additional pipeline capacity that came online during the year.

·

We reported net income of $249.3 million in the fourth quarter of 2018 compared to net income of $15.3 million in the fourth quarter of 2017. Net income increased by $234.0 million primarily due to a $253.7 million gain on commodity derivative instruments in 2018 compared to a $41.0 million loss recorded in 2017.

·

Cash flow from operating activities and adjusted funds flow increased to $221.6 million and $214.3 million, respectively, compared to $135.3 million and $199.6 million, respectively, in the fourth quarter of 2017. The increases were the result of higher production and stronger natural gas prices in the Marcellus offset by wider Bakken crude oil differentials in the fourth quarter of 2018.

·

During the fourth quarter of 2018, we repurchased 5.4 million common shares under our Normal Course Issuer Bid (“NCIB”) for total consideration of $70.6 million, bringing our total repurchases to 5.9 million shares for total consideration of $79.0 million in 2018.

·

Net debt to adjusted funds flow improved to 0.4x compared to 0.6x in the fourth quarter of 2017.

2018 OVERVIEW AND 2019 OUTLOOK

 

 

 

 

 

 

 

 

Summary of Guidance and Results

 

Revised 2018 Guidance

 

2018 Results

 

2019 Guidance

 

Capital spending ($ millions)

 

$
585

 

$
594

 

$565 - $635

 

Average annual production (BOE/day)

 

92,500 - 93,000

 

93,216

 

94,000 – 100,000

 

Average annual crude oil and natural gas liquids production (bbls/day)

 

49,500 - 50,000

 

49,910

 

52,500 – 56,000

 

Fourth quarter average crude oil and natural gas liquids production (bbls/day)

 

53,500 - 54,500

 

54,451

 

 

 

Average royalty and production tax rate
(% of gross sales, before transportation)

 

25%

 

25%

 

25%

 

Operating expenses (per BOE)

 

$
7.00

 

$
7.00

 

$
8.00

 

Transportation costs (per BOE)

 

$
3.60

 

$
3.63

 

$
4.00

 

Cash G&A expenses (per BOE)

 

$
1.50

 

$
1.47

 

$
1.50

 

 

 

 

 

 

 

 

 

2019 Differential/Basis Outlook and Results (1)

 

 

 

 

 

 

 

Average U.S. Bakken crude oil differential (compared to WTI crude oil)

 

US$(3.80)/bbl

 

US$(3.78)/bbl

 

US$(4.00)/bbl

 

Average Marcellus natural gas differential (compared to NYMEX natural gas)

 

US$(0.40)/Mcf

 

US$(0.43)/Mcf

 

US$(0.30)/Mcf

 

(1)

Excludes transportation costs

6               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

2018 Overview

In 2018, we continued to focus on maximizing returns, sustainable growth, as well as returning capital to our shareholders. We delivered total production growth of 10% and liquids growth of 22% compared to 2017 and returned $108.3 million of capital to our shareholders through share repurchases and dividends, while maintaining our balance sheet strength.

In 2018, our annual average production was 93,216 BOE/day with crude oil and liquids volumes of 49,910 bbls/day, at the high end of our revised production guidance targets of 92,500 – 93,000 BOE/day and 49,500 – 50,000 bbls/day, respectively. Our capital spending for the year totaled $593.9 million, in line with our guidance of $585 million. The majority of our spending (88%) was focused on our liquids properties, primarily in North Dakota. 

Our Bakken sales price differentials remained consistent with the prior year averaging US$3.78/bbl below WTI, which was in line with our revised guidance of US$3.80/bbl below WTI. Our Marcellus differential narrowed to US$0.43/Mcf below NYMEX, a 43% improvement compared to 2017,  due to additional pipeline capacity coming into service. Canadian crude oil and natural gas differentials weakened  significantly in 2018, averaging US$21.83/bbl below WTI and US$0.81/Mcf below NYMEX, respectively, mainly due to limited pipeline takeaway capacity and  storage concerns. 

Operating expenses and cash G&A expenses were $7.00/BOE and $1.47/BOE, respectively, consistent with our guidance of $7.00/BOE and $1.50/BOE, respectively.

Net income for 2018 was $378.3 million, an increase from $237.0 million in 2017 primarily due to higher revenue as a result of an increase in production,  realized pricing and gains on commodity derivative instruments. The higher production also increased operating, royalty and depletion expenses, which partially offset the higher revenue in 2018 when compared to 2017.  

Cash flow from operations and adjusted funds flow increased significantly to $738.8 million and $753.5 million, respectively, from $476.1 million and $524.1 million, respectively, in 2017. Oil and natural gas sales increased by $469.1 million, compared to 2017, largely due to higher realized commodity prices, narrower sales price differentials in the Marcellus and higher production volumes. This increase was partially offset by higher operating and royalty expenses in 2018.

Total debt net of cash at December 31, 2018 was $333.5 million, comprised of $696.8 million of senior notes less $363.3 million in cash. At December 31, 2018, we were undrawn on our $800 million senior unsecured bank credit facility and had a net debt to adjusted funds flow ratio of 0.4x.   

2019 Outlook

Our focus in 2019 is to continue to maximize returns, while delivering sustainable liquids production growth, returning capital to shareholders and preserving our balance sheet strength. Our capital budget range for 2019 is between $565 million and $635 million, with the majority of capital being allocated to our North Dakota crude oil properties. As a result, we expect annual liquids production growth of approximately 9% at the mid-point of production guidance in 2019.

Annual 2019 production is expected to average between 94,000 – 100,000 BOE/day, with crude oil and natural gas liquids production expected to average between 52,500 – 56,000 bbls/day. As a result of lower capital spending in the fourth quarter of 2018, we expect the majority of our production growth to occur during the second half of 2019.

We expect our Bakken sales price differential to widen slightly in 2019 to be approximately US$4.00/bbl below WTI, which includes 16,000 bbls/day of fixed price differential sales at approximately US$3.00/bbl below WTI. In the Marcellus, we expect our sales price differential to improve to approximately US$0.30/Mcf below NYMEX as a result of excess pipeline egress out of the region. 

To support our 2019 capital program, we have hedged 63% of our 2019 forecasted crude oil production, after royalties, primarily through the use of three-way collar structures. We also have additional natural gas hedges in 2019 for approximately 34% of our forecasted 2019 natural gas production, after royalties.

Operating expenses are expected to average approximately $8.00/BOE in 2019, an increase from 2018, as a result of the increase to our crude oil and liquids weighting throughout 2019, as well as an increase in gas processing costs and the use of electrical submersible pumps in North Dakota. We continue to focus our capital program on crude oil production growth, which has higher operating cost metrics. 

We expect cash G&A expenses and transportation costs for 2019 to average approximately $1.50/BOE and $4.00/BOE, respectively. The increase in transportation costs reflects additional transportation commitments that provide access to sell a portion of our production at U.S. gulf coast or Brent pricing.

 

ENERPLUS 2018 FINANCIAL SUMMARY              7

 

 

         

RESULTS OF OPERATIONS

Production

 

 

 

 

 

 

 

 

 

 

Average Daily Production Volumes

 

 

2018

 

 

2017

 

 

2016

Crude oil (bbls/day)

 

 

45,424

 

 

36,935

 

 

38,353

Natural gas liquids (bbls/day)

 

 

4,486

 

 

3,858

 

 

4,903

Natural gas (Mcf/day)

 

 

259,837

 

 

263,506

 

 

299,214

Total daily sales (BOE/day)

 

 

93,216

 

 

84,711

 

 

93,125

 

Production in 2018 averaged 93,216 BOE/day, in line with our revised guidance range of 92,500  – 93,000 BOE/day and a 10% increase when compared to 2017. Crude oil and liquids production averaged 49,910 BOE/day, meeting our revised guidance of 49,500  – 50,000 bbls/day, as a result of a successful capital program focused on our U.S. crude oil properties.

Our U.S. production volumes increased by 20% to 78,287 BOE/day compared to 2017, mainly due to a 10,743 bbl/day increase in crude oil and natural gas liquids production as a result of strong well performance in North Dakota and an increase to our 2018 capital spending program. Our U.S. natural gas production increased by 7% with no price related curtailments in the Marcellus during the year.

Canadian production volumes decreased by 4,748 BOE/day or 24% compared to the prior year, largely due to the full year impact of non-core asset divestments that occurred throughout 2017.

Our crude oil and natural gas liquids production accounted for 54% of our total average daily production in 2018, a significant increase when compared to 48% in 2017 and 46% in 2016.

Production for 2017 compared to 2016 decreased 9% or 8,414 bbls/day. The decrease was primarily a result of non-core Canadian divestments throughout 2017 and the sale of our U.S. non-operated North Dakota properties, which closed on December 30, 2016. The impact of divestments was somewhat offset by growth in our operated U.S. crude oil production with the additional capital spending on our North Dakota assets. 

2019 Guidance

We expect annual   average production for 2019 of 94,000 – 100,000 BOE/day, including 52,500 – 56,000 bbls/day of crude oil and natural gas liquids, resulting in year over year production growth of 4% and liquids production growth of 9% based on  a WTI price of US$50/bbl – US$55/bbl.

Pricing

The prices received for our crude oil and natural gas production directly impact our earnings, cash flow from operating activities, adjusted funds flow and financial condition. The following table summarizes our average selling prices, benchmark prices and differentials:

 

 

 

 

 

 

 

 

 

 

Pricing  (average for the period)

    

2018

    

2017

    

2016

Benchmarks

 

 

 

 

 

 

 

 

 

WTI crude oil (US$/bbl)

 

$

64.77

 

$

50.95

 

$

43.32

Brent (ICE) crude oil (US$/bbl)

 

 

71.53

 

 

54.83

 

 

45.04

NYMEX natural gas – last day (US$/Mcf)

 

 

3.09

 

 

3.11

 

 

2.46

AECO natural gas – monthly index ($/Mcf)

 

 

1.53

 

 

2.43

 

 

2.09

US/CDN average exchange rate

 

 

1.30

 

 

1.30

 

 

1.32

US/CDN period end exchange rate

 

 

1.36

 

 

1.26

 

 

1.34

 

 

 

 

 

 

 

 

 

 

Enerplus selling price (1)

 

 

 

 

 

 

 

 

 

Crude oil ($/bbl)

 

$

74.59

 

$

58.69

 

$

44.84

Natural gas liquids ($/bbl)

 

 

28.31

 

 

30.01

 

 

15.29

Natural gas ($/Mcf)

 

 

3.42

 

 

3.21

 

 

2.06

 

 

 

 

 

 

 

 

 

 

Average benchmark differentials

 

 

 

 

 

 

 

 

 

Brent (ICE) - WTI (US$/bbl)

 

$

6.77

 

$

3.88

 

$

1.72

MSW Edmonton – WTI (US$/bbl)

 

 

(11.12)

 

 

(2.46)

 

 

(3.21)

WCS Hardisty – WTI (US$/bbl)

 

 

(26.31)

 

 

(11.98)

 

 

(13.84)

Transco Leidy monthly – NYMEX (US$/Mcf)

 

 

(0.64)

 

 

(0.96)

 

 

(1.15)

TGP Z4 300L monthly – NYMEX (US$/Mcf)

 

 

(0.73)

 

 

(1.03)

 

 

(1.21)

AECO monthly – NYMEX (US$/Mcf)

 

 

(1.90)

 

 

(1.26)

 

 

(0.89)

 

 

 

 

 

 

 

 

 

 

8               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

 

Enerplus realized differentials (1)(2)

 

 

 

 

 

 

 

 

 

Bakken crude oil – WTI (US$/bbl)

 

$

(3.78)

 

$

(3.72)

 

$

(7.46)

Marcellus natural gas – NYMEX (US$/Mcf)

 

 

(0.43)

 

 

(0.76)

 

 

(0.93)

Canada crude oil – WTI (US$/bbl)

 

 

(21.83)

 

 

(10.94)

 

 

(13.21)

Canada natural gas – NYMEX (US$/Mcf)

 

 

(0.81)

 

 

(0.62)

 

 

(0.80)

(1)

Excluding transportation costs, royalties and the effects of commodity derivative instruments.

(2)

Based on a weighted average differential for the period.

 

CRUDE OIL AND NATURAL GAS LIQUIDS

Benchmark WTI prices increased by 27% to US$64.77/bbl in 2018 compared to 2017, largely due to lower global inventories as a result of the supply reductions made by the Organization of Petroleum Exporting Countries (“OPEC”). In addition, supply concerns, particularly in Venezuela, and the reimposition of U.S. sanctions on Iran supported global crude oil prices for the majority of the year. However, WTI prices declined significantly during the fourth quarter of 2018,  closing at US$45.41/bbl. The decline in oil prices was due to concerns over global trade and ongoing geopolitical issues, which may reduce global demand.  Our 2018 realized crude oil price averaged $74.59/bbl, a 27% increase compared to 2017, in line with changes in the underlying benchmark price.

 

Our Bakken sales price differentials weakened slightly in 2018 compared to the prior year, averaging US$3.78/bbl below WTI, which was in line with our revised guidance of US$3.80/bbl below WTI. Bakken prices were strong during the second and third quarter of 2018 but weakened significantly during the fourth quarter. This was due to a large amount of demand lost during seasonal refinery maintenance and higher than anticipated production increases that put pressure on regional pipeline capacity. Our realized Bakken differentials were somewhat insulated from the weakness in the fourth quarter of 2018 due to a portion of our physical sales being based on term negotiated fixed differentials to WTI. We expect Bakken differentials to widen slightly in 2019 and are guiding to US$4.00/bbl below WTI,  which includes 16,000 bbls/day of fixed price differential sales at approximately US$3.00/bbl below WTI.  

 

Canadian crude oil differentials weakened substantially in 2018, with both heavy and light differentials trading at much wider levels compared to the prior year. This was especially evident during the fourth quarter of 2018, as pipeline capacity leaving the region was fully utilized, resulting in a large increase in Canadian crude oil held in storage and a significant volume of production using rail to clear the region. However, differentials have recently strengthened due to Alberta government mandated production curtailments, which were announced in December 2018. Inadequate pipeline takeaway continues to be a major concern throughout the Canadian oil and gas industry. 

 

We realized an average price of $28.31/bbl on our natural gas liquids production in 2018, which represents a 6% decrease in prices when compared to 2017. This decrease was mainly due to lower condensate prices in both Canada and the U.S.

NATURAL GAS

Our realized natural gas price averaged $3.42/Mcf in 2018, a 7% increase from 2017 realized prices, despite NYMEX and AECO prices both declining on a year-over-year basis. Our realized natural gas price outperformed the benchmarks due to stronger Marcellus basis differentials in 2018 and the positive impact of our multi-year term AECO physical sales which had average fixed basis differentials of US$0.64/Mcf below NYMEX.

 

In the Marcellus, the Tennessee Gas Pipeline Zone 4 - 300 Leg and Transco Leidy monthly benchmark differentials averaged US$0.73/Mcf and US$0.64/Mcf below NYMEX, respectively, compared to US$1.03/Mcf and US$0.96/Mcf, respectively, below NYMEX in 2017. The strengthening in local Marcellus prices was due to additional pipeline capacity coming into service, as well as stronger weather-related demand in the region. As a result, our realized portfolio sales price differential, before transportation costs, averaged US$0.43/Mcf below NYMEX for the year, which was in line with our guidance of US$0.40/Mcf below NYMEX. We expect our Marcellus differential to average US$0.30/Mcf below NYMEX in 2019 as regional prices continue to benefit from excess pipeline takeaway capacity.

 

In Alberta, congestion on regional and export pipelines and continued production growth resulted in benchmark AECO monthly prices averaging US$1.90/Mcf below NYMEX in 2018 compared to US$1.26/Mcf below NYMEX in 2017. We continue to benefit from our term AECO physical sales. 

 

ENERPLUS 2018 FINANCIAL SUMMARY              9

 

 

         

Monthly Crude Oil Prices 

PICTURE 6

Monthly Natural Gas Prices 

PICTURE 4

FOREIGN EXCHANGE

Our oil and natural gas sales are impacted by foreign exchange fluctuations as the majority of our sales are based on U.S. dollar denominated benchmark indices. A weaker Canadian dollar increases the amount of our realized sales, as well as the amount of our U.S. denominated costs, such as capital, interest on our U.S. denominated debt, and the value of our outstanding U.S. senior notes.

The Canadian dollar weakened throughout 2018, closing the year at 1.36 US/CDN compared to 1.26 US/CDN at December 31, 2017 and averaging 1.30 US/CDN throughout the year. The weakness in the Canadian dollar was driven by decelerating domestic economic growth, changing U.S. and Canada trade policies including the renegotiation of the North American Free Trade Agreement, as well as interest rates in the U.S. and Canada.

10               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

Monthly USD/CDN Exchange Rate 

PICTURE 5

Price Risk Management

We have a price risk management program that considers our overall financial position and the economics of our capital expenditures.  

As of February 20, 2019,  we have hedged approximately 23,100 bbls/day of our expected crude oil production for 2019, which represents approximately 63% of our 2019 forecasted crude oil production, after royalties. For 2020, we have hedged 16,000 bbls/day, which represents approximately 43%  of our 2019 forecasted crude oil production, after royalties. Our crude oil hedges are predominantly three-way collars, which consist of a sold put, a purchased put and a sold call. When WTI prices settle below the sold put strike price, the three-way collars provide a limited amount of protection above the WTI settled price equal to the difference between the strike price of the purchased and sold puts. Overall, we expect our crude oil related hedging contracts to protect a significant portion of our cash flow from operating activities and adjusted funds flow.

 

As of February 20, 2019,  we have hedged approximately 65,700 Mcf/day of our forecasted natural gas production for 2019. This represents approximately 34% of our forecasted natural gas production, after royalties.    

 

The following is a summary of our financial contracts in place at February 20, 2019, expressed as a percentage of our forecasted 2019 net production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

WTI Crude Oil (US$/bbl) (1)(2)

 

    

Jan 1, 2019 – 

    

Apr 1, 2019 – 

    

July 1, 2019 – 

    

Oct 1, 2019 – 

    

Jan 1, 2020 – 

 

 

Mar 31, 2019

 

Jun 30, 2019

 

Sep 30, 2019

 

Dec 31, 2019

 

Dec 31, 2020

Swaps

 

 

 

 

 

 

 

 

 

 

Sold Swaps

 

$ 53.73

 

-

 

-

 

-

 

-

%

 

8%

 

-

 

-

 

-

 

-

 

 

 

 

 

 

 

 

 

 

 

Three Way Collars

 

 

 

 

 

 

 

 

 

 

Sold Puts

 

$ 44.28

 

$ 44.50

 

$ 44.64

 

$ 44.64

 

$ 46.88

%

 

46%

 

63%

 

66%

 

66%

 

43%

Purchased Puts

 

$ 54.12

 

$ 54.59

 

$ 54.81

 

$ 54.81

 

$ 57.50

%

 

46%

 

63%

 

66%

 

66%

 

43%

Sold Calls

 

$ 64.12

 

$ 65.52

 

$ 65.95

 

$ 65.99

 

$ 72.50

%

 

46%

 

63%

 

66%

 

66%

 

43%

(1)

Based on weighted average price (before premiums) assuming average annual production of 97,000 BOE/day, which is the mid-point of our annual 2019 guidance, less royalties and production taxes of 25%. A portion of the sold puts are settled annually rather than monthly.

(2)

The total average deferred premium spent on our three-way collars is US$1.61/bbl from January 1, 2019 to December 31, 2020.

ENERPLUS 2018 FINANCIAL SUMMARY              11

 

 

         

 

 

 

 

 

 

 

 

 

 

 

NYMEX Natural Gas (US$/Mcf) (1)  

 

 

 

    

Jan 1, 2019 – 

    

Apr 1, 2019 – 

 

 

 

 

Mar 31, 2019

 

Oct 31, 2019

Swaps

 

 

 

 

 

 

Sold Swaps

 

 

 

$ 4.23

 

$ 2.85

%

 

 

 

26%

 

36%

 

 

 

 

 

 

 

Collars

 

 

 

 

 

 

Purchased Puts

 

 

 

$ 3.80

 

-

%

 

 

 

26%

 

-

Sold Calls

 

 

 

$ 6.01

 

-

%

 

 

 

26%

 

 -

(1)

Based on weighted average price (before premiums) assuming average annual production of 97,000 BOE/day, which is the mid-point of our annual 2019 guidance, less royalties and production taxes of 25%.

 

ACCOUNTING FOR PRICE RISK MANAGEMENT

 

 

 

 

 

 

 

 

 

 

Commodity Risk Management Gains/(Losses)

 

 

 

 

 

 

 

 

 

($ millions)

    

2018

    

2017

    

2016

Cash gains/(losses):

 

 

 

 

 

 

 

 

 

Crude oil

 

$

(52.0)

 

$

0.9

 

$

75.0

Natural gas

 

 

16.2

 

 

7.7

 

 

5.3

Total cash gains/(losses)

 

$

(35.8)

 

$

8.6

 

$

80.3

 

 

 

 

 

 

 

 

 

 

Non-cash gains/(losses):

 

 

 

 

 

 

 

 

 

Crude oil

 

$

114.8

 

$

(5.4)

 

$

(96.2)

Natural gas

 

 

9.2

 

 

11.1

 

 

(13.5)

Total non-cash gains/(losses)

 

$

124.0

 

$

5.7

 

$

(109.7)

Total gains/(losses)

 

$

88.2

 

$

14.3

 

$

(29.4)

 

 

 

 

 

 

 

 

 

 

 

(Per BOE)

    

2018

    

2017

    

2016

Total cash gains/(losses)

 

$

(1.05)

 

$

0.28

 

$

2.36

Total non-cash gains/(losses)

 

 

3.64

 

 

0.18

 

 

(3.22)

Total gains/(losses)

 

$

2.59

 

$

0.46

 

$

(0.86)

 

During 2018, we realized cash losses of $52.0 million on our crude oil contracts and gains of $16.2 million on our natural gas contracts. The realized cash losses were the result of crude oil prices rising above the swap level and the sold call strike price on our three-way collars. Cash gains on our natural gas contracts included a gain of $15.1 million on the unwind of a portion of our AECO-NYMEX basis physical contracts. In 2017, we realized cash gains of $0.9 million on our crude oil contracts and $7.7 million on our natural gas contracts, which included a gain of $8.5 million on the unwind of a portion of our AECO-NYMEX basis physical contracts. During 2016, we realized cash gains of $75.0 million on our crude oil contracts and $5.3 million on our natural gas contracts. The cash gains in 2017 and 2016 were due to contracts which provided floor protection above market prices.

As the forward markets for crude oil and natural gas fluctuate, as new contracts are executed, and as existing contracts are realized, changes in fair value are reflected as either a non‑cash charge or gain to earnings. The fair value of our crude oil contracts and natural gas contracts at December 31, 2018 were in a net asset position of $80.5 million and $10.9 million, respectively (December 31, 2017 – net liability position of $34.3 million and net asset position of $1.7 million, respectively). The change in fair value of our crude oil and natural gas contracts represented gains of $114.8 million and $9.2 million, respectively, during 2018 and losses of $5.4 million and gains of $11.1 million, respectively, during 2017.

Revenues

 

 

 

 

 

 

 

 

 

 

($ millions)

    

2018

    

2017

    

2016

Oil and natural gas sales

 

$

1,610.9

 

$

1,141.8

 

$

882.1

Royalties

 

 

(318.2)

 

 

(221.1)

 

 

(159.4)

Oil and natural gas sales, net of royalties

 

$

1,292.7

 

$

920.7

 

$

722.7

 

Oil and natural gas sales revenue for 2018 totaled $1,610.9 million, an increase of 41% from $1,141.8 million in 2017.  The increase in revenue was a result of higher liquids production and an improvement in crude oil prices.

 

In 2017, oil and natural gas sales revenue increased 29% to $1,141.8 million from $882.1 million in 2016. The increase in 2017 is a result of the improvement in commodity prices and realized sales price differentials, along with a higher crude oil and natural gas liquids weighting of 48% compared to 46% in 2016.

12               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

Royalties and Production Taxes

 

 

 

 

 

 

 

 

 

 

 

($ millions, except per BOE amounts)

    

2018

    

2017

    

2016

 

Royalties

 

$

318.2

 

$

221.1

 

$

159.4

 

Per BOE

 

$

9.35

 

$

7.15

 

$

4.67

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

 

$

87.3

 

$

54.3

 

$

37.4

 

Per BOE

 

$

2.57

 

$

1.76

 

$

1.10

 

Royalties and production taxes

 

$

405.5

 

$

275.4

 

$

196.8

 

Per BOE

 

$

11.92

 

$

8.91

 

$

5.77

 

 

 

 

 

 

 

 

 

 

 

 

Royalties and production taxes (% of oil and natural gas sales)

 

 

25%

 

 

24%

 

 

22%

 

 

Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees and freehold mineral taxes.  A large percentage of our production is from U.S. properties where royalty rates are generally higher than in Canada and less sensitive to commodity price levels.

Royalties and production taxes were in line with our guidance for 2018, averaging 25% of oil and natural gas sales, before transportation. Royalties and production taxes increased to $405.5 million in 2018 from $275.4 million in 2017 and $196.8 million in 2016, mainly due to a larger portion of production volumes coming from our U.S. properties, as well as higher crude oil and natural gas realized prices.

2019 Guidance

We expect royalty and production taxes in 2019 to average 25% of our oil and gas sales before transportation, which is consistent with 2018 levels.

Operating Expenses

 

 

 

 

 

 

 

 

 

 

($ millions, except per BOE amounts)

    

2018

    

2017

    

2016

Cash operating expenses

 

$

238.3

 

$

197.7

 

$

249.0

Non-cash (gains)/losses (1)

 

 

 -

 

 

(0.6)

 

 

(1.1)

Total operating expenses

 

$

238.3

 

$

197.1

 

$

247.9

Per BOE

 

$

7.00

 

$

6.37

 

$

7.27

(1)

Non-cash (gains)/losses on fixed price electricity swaps.

Operating expenses for 2018 were $238.3 million or $7.00/BOE, consistent with our revised guidance of $7.00/BOE and representing an increase of $41.2 million ($0.63/BOE) from the prior year. The increase is mainly attributable to our higher liquids production as our liquids weighting increased to 54% from 48% in the prior year. Our liquids production has higher associated operating cost metrics, which was partially offset by the divestment of higher operating cost Canadian properties during 2017.  

Operating expenses during 2017 were $197.1 million or $6.37/BOE compared to $247.9 million or $7.27/BOE in 2016. The improvement was mainly the result of cost savings initiatives combined with the divestment of higher operating cost Canadian properties. 

2019 Guidance

We expect operating expenses of $8.00/BOE in 2019. The increase from 2018 is primarily a result of our liquids growth contributing to a higher proportion of our total production, as well as an increase in gas processing costs and use of electrical submersible pumps in North Dakota.

Transportation Costs

 

 

 

 

 

 

 

 

 

 

($ millions, except per BOE amounts)

    

2018

    

2017

    

2016

Transportation costs

 

$

123.5

 

$

111.3

 

$

107.1

Per BOE

 

$

3.63

 

$

3.60

 

$

3.14

 

 

 

 

 

 



ENERPLUS 2018 FINANCIAL SUMMARY              13

 

 

         

Transportation costs in 2018 were in line with our guidance of $3.60/BOE averaging $3.63/BOE, and similar to $3.60/BOE in 2017. Transportation costs increased to $3.60/BOE in 2017, compared to $3.14/BOE in 2016 due to additional transportation commitments in the Marcellus that commenced in August 2016 and our  growing U.S. production volumes which have higher associated transportation costs. 

2019 Guidance

We expect transportation costs to increase to $4.00/BOE in 2019, due to additional crude oil firm transportation commitments that provide access to sell a portion of our production at U.S. gulf coast or Brent pricing. 

Netbacks

The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such, the revenue per BOE or per Mcfe may not correspond with the average selling price under the “Pricing” section of this MD&A.

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2018

Netbacks by Property Type

    

Crude Oil

   

Natural Gas

   

Total

Average Daily Production

 

 

53,294 BOE/day

 

 

239,532 Mcfe/day

 

 

93,216 BOE/day

Netback (1) $ per BOE or Mcfe

 

 

(per BOE)

 

 

(per Mcfe)

 

 

(per BOE)

Oil and natural gas sales

 

$

67.43

 

$

3.42

 

$

47.35

Royalties and production taxes

 

 

(17.90)

 

 

(0.65)

 

 

(11.92)

Cash operating expenses

 

 

(10.54)

 

 

(0.38)

 

 

(7.00)

Transportation costs

 

 

(2.40)

 

 

(0.88)

 

 

(3.63)

Netback before hedging

 

$

36.59

 

$

1.51

 

$

24.80

Cash gains/(losses)

 

 

(2.67)

 

 

0.19

 

 

(1.05)

Netback after hedging

 

$

33.92

 

$

1.70

 

$

23.75

Netback before hedging ($ millions)

 

$

711.7

 

$

131.9

 

$

843.6

Netback after hedging ($ millions)

 

$

659.7

 

$

148.1

 

$

807.8

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2017

Netbacks by Property Type

    

Crude Oil

    

Natural Gas

    

Total

Average Daily Production

 

 

44,496 BOE/day

 

 

241,290 Mcfe/day

 

 

84,711 BOE/day

Netback (1) $ per BOE or Mcfe

 

 

(per BOE)

 

 

(per Mcfe)

 

 

(per BOE)

Oil and natural gas sales

 

$

53.38

 

$

3.12

 

$

36.93

Royalties and production taxes

 

 

(13.89)

 

 

(0.57)

 

 

(8.91)

Cash operating expenses

 

 

(10.20)

 

 

(0.36)

 

 

(6.39)

Transportation costs

 

 

(2.21)

 

 

(0.86)

 

 

(3.60)

Netback before hedging

 

$

27.08

 

$

1.33

 

$

18.03

Cash gains/(losses)

 

 

0.06

 

 

0.09

 

 

0.28

Netback after hedging

 

$

27.14

 

$

1.42

 

$

18.31

Netback before hedging ($ millions)

 

$

439.8

 

$

117.6

 

$

557.4

Netback after hedging ($ millions)

 

$

440.7

 

$

125.2

 

$

566.0

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2016

Netbacks by Property Type

 

Crude Oil

 

Natural Gas

 

Total

Average Daily Production

    

 

47,206 BOE/day

 

 

275,538 Mcfe/day

 

 

93,125 BOE/day

Netback (1) $ per BOE or Mcfe

 

 

(per BOE)

 

 

(per Mcfe)

 

 

(per BOE)

Oil and natural gas sales

 

$

37.86

 

$

2.26

 

$

25.88

Royalties and production taxes

 

 

(9.38)

 

 

(0.34)

 

 

(5.77)

Cash operating expenses

 

 

(10.29)

 

 

(0.72)

 

 

(7.31)

Transportation costs

 

 

(1.97)

 

 

(0.72)

 

 

(3.14)

Netback before hedging

 

$

16.22

 

$

0.48

 

$

9.66

Cash gains/(losses)

 

 

4.34

 

 

0.05

 

 

2.36

Netback after hedging

 

$

20.56

 

$

0.53

 

$

12.02

Netback before hedging ($ millions)

 

$

280.4

 

$

48.8

 

$

329.2

Netback after hedging ($ millions)

 

$

355.3

 

$

54.2

 

$

409.5

(1)

See “Non‑GAAP Measures” in this MD&A.

 

 

14               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

Crude oil and natural gas netbacks per BOE before hedging were higher during 2018 compared to 2017 and 2016 primarily due to higher realized crude oil prices. During 2018, our crude oil properties accounted for 84% and 82% of our netback before and after hedging, respectively. During 2017, our crude oil properties accounted for 79% and 78% of our netback before and after hedging, respectively.

 

General and Administrative Expenses

Total G&A expenses include cash G&A expenses and share‑based compensation (“SBC”) charges related to our long‑term incentive plans (“LTI plans”). See Note 10, Note 13 and Note 14 to the Financial Statements for further details.

 

 

 

 

 

 

 

 

 

 

($ millions)

    

2018

    

2017

    

2016

Cash:

 

 

 

 

 

 

 

 

 

G&A expense

 

$

50.0

 

$

50.5

 

$

59.8

Share-based compensation expense

 

 

0.1

 

 

1.0

 

 

3.1

 

 

 

 

 

 

 

 

 

 

Non-Cash:

 

 

 

 

 

 

 

 

 

Share-based compensation expense

 

 

25.9

 

 

22.6

 

 

27.0

Equity swap loss/(gain)

 

 

(0.2)

 

 

0.2

 

 

(3.6)

Total G&A expenses

 

$

75.8

 

$

74.3

 

$

86.3

 

 

 

 

 

 

 

 

 

 

 

(Per BOE)

    

2018

    

2017

    

2016

Cash:

 

 

 

 

 

 

 

 

 

G&A expense

 

$

1.47

 

$

1.63

 

$

1.75

Share-based compensation expense

 

 

0.01

 

 

0.03

 

 

0.09

 

 

 

 

 

 

 

 

 

 

Non-Cash:

 

 

 

 

 

 

 

 

 

Share-based compensation expense

 

 

0.76

 

 

0.73

 

 

0.80

Equity swap loss/(gain)

 

 

(0.01)

 

 

0.01

 

 

(0.11)

Total G&A expenses

 

$

2.23

 

$

2.40

 

$

2.53

 

Cash G&A expenses in 2018 totaled $50.0 million ($1.47/BOE), beating our guidance of $1.50/BOE and consistent with $50.5 million ($1.63/BOE) in 2017. 

During the year, we reported cash SBC on our Deferred Share Unit (“DSU”) plan of $0.1 million, compared to $1.0 million in 2017 due to  a decrease in our share price at December 31, 2018 on outstanding deferred share units. We recorded non‑cash SBC of $25.9 million ($0.76/BOE) in 2018 compared to $22.6 million ($0.73/BOE) in 2017. The increase in non-cash SBC in 2018 was a result of a recovery recorded in 2017 due to the forfeiture of units that were previously expensed.  

Cash G&A expenses in 2017 were $50.5 million ($1.63/BOE), a decrease of 16% from $59.8 million ($1.75/BOE) in 2016. Cash SBC expense was $1.0 million ($0.03/BOE) in 2017 compared to an expense of $3.1 million ($0.09/BOE) in 2016. We recorded non‑cash SBC of $22.6 million ($0.73/BOE) in 2017 compared to $27.0 million ($0.80/BOE) in 2016. The decrease in non-cash SBC was a result of the increased forfeiture of units in 2017.

We have hedged a portion of the outstanding cash‑settled units under our LTI plans. We recorded a non‑cash mark‑to‑market gain of $0.2 million on these hedges in 2018 (2017 – $0.2 million loss; 2016 – $3.6 million gain), which included the settlement of a portion of our equity swaps. As of December 31, 2018, we have 195,000 units hedged at a weighted average price of $20.60 per share.

2019 Guidance

We expect   our cash G&A expense to be $1.50/BOE in 2019, which is consistent with 2018. 

Interest Expense

Interest on our senior notes and bank credit facility in 2018 totaled $36.8 million compared to $38.7 million in 2017 and $45.4 million in 2016. Interest expense decreased 5% in 2018 when compared to 2017 primarily due to the repayment of a portion of our 2009 senior notes which carry a higher coupon rate.  

Interest expense decreased 15% in 2017 when compared to 2016 due to our undrawn bank credit facility, the impact of the strengthening Canadian dollar on our U.S. denominated interest payments and the payment of the first of five annual principal instalments on our 2009 senior notes.

 

ENERPLUS 2018 FINANCIAL SUMMARY              15

 

 

         

At December 31, 2018, we were undrawn on our $800 million bank credit facility and our debt consisted of fixed interest rate senior notes with a weighted average interest rate of 4.8%. See Note 7 to the Financial Statements for further details on our outstanding notes.

Foreign Exchange

 

 

 

 

 

 

 

 

 

 

($ millions)

    

2018

    

2017

    

2016

Realized:

 

 

 

 

 

 

 

 

 

Foreign exchange loss/(gain) on settlements

 

$

0.5

 

$

1.5

 

$

0.1

Translation of U.S. dollar cash held in Canada loss/(gain)

 

 

(19.6)

 

 

11.0

 

 

 —

Unrealized loss/(gain)

 

 

58.6

 

 

(42.6)

 

 

(40.6)

Total foreign exchange loss/(gain)

 

$

39.5

 

$

(30.1)

 

$

(40.5)

US/CDN average exchange rate

 

 

1.30

 

 

1.30

 

 

1.32

US/CDN period end exchange rate

 

 

1.36

 

 

1.26

 

 

1.34

 

We recorded a net foreign exchange loss of $39.5 million in 2018 compared to gains of $30.1 million and $40.5 million in 2017 and 2016, respectively. Realized gains and losses relate primarily to day-to-day transactions recorded in foreign currencies, along with the translation of our U.S. dollar denominated cash held in Canada, while unrealized gains and losses are recorded on the translation of our U.S. dollar denominated debt and working capital at each period-end.

In 2018, we recorded a realized foreign exchange gain of $19.1 million, due to the weakening Canadian dollar compared to a loss of $12.5 million and $0.1 million in 2017 and 2016, respectively.

Comparing December 31, 2018 to December 31, 2017, the Canadian dollar weakened relative to the U.S. dollar, resulting in an unrealized loss of $58.6 million. See Note 11 to the Financial Statements for further details. 

Capital Investment

 

 

 

 

 

 

 

 

 

 

($ millions)

    

2018

    

2017

    

2016

Capital spending

 

$

593.9

 

$

458.0

 

$

209.1

Office capital

 

 

6.5

 

 

2.7

 

 

1.5

Sub-total

 

 

600.4

 

 

460.7

 

 

210.6

Property and land acquisitions

 

$

25.8

 

$

13.3

 

$

126.1

Property divestments

 

 

(6.9)

 

 

(56.2)

 

 

(670.4)

Sub-total

 

 

18.9

 

 

(42.9)

 

 

(544.3)

Total (1)

 

$

619.3

 

$

417.8

 

$

(333.7)

(1)

Excludes changes in non-cash investing working capital. See Note 17(b) of the Consolidated Financial Statements for additional information.

2018

Capital spending in 2018 totaled $593.9 million, in line with our guidance of $585 million. Our capital spending in 2018 was 30% higher than 2017, as we continued to execute on our growth plans. In 2018, we spent $474.4 million on our U.S. crude oil properties, $46.3 million on our Canadian crude oil properties, and $66.2 million on our Marcellus natural gas assets. Through our capital program in 2018, we added 65.7 MMBOE of gross proved plus probable reserves, replacing 194% of our 2018 production, before accounting for acquisitions and divestments.

Property and land acquisitions in 2018 totaled $25.8 million and included land acquisitions in Colorado and a property swap in North Dakota. We recorded net divestments of $6.9 million in 2018, primarily related to a property swap in North Dakota.

2017

Capital spending in 2017 totaled $458.0 million and was more than twice our spending levels in 2016, as we repositioned ourselves for growth. In 2017 we spent $343.0 million on our U.S. crude oil properties, $55.3 million on our Canadian crude oil properties, and $58.5 million on our Marcellus natural gas assets. In 2017, we added 58.0 MMBOE of gross proved plus probable reserves, replacing 189% of our 2017 production, before accounting for acquisitions and divestments.

We recorded net divestment proceeds of $56.2 million in 2017 consisting mainly of our second quarter sale of our Brooks waterflood property and Canadian shallow gas assets. Total divestments had combined production of 7,700 BOE/day and resulted in a $72.3 million reduction to future asset retirement obligations. Property and land acquisitions in 2017 totaled $13.3 million and included additional leases and minor undeveloped land.

16               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

2016

Capital spending in 2016 totaled $209.1 million and was focused on our core areas with spending of $136.4 million on our North Dakota crude oil properties, $44.4 million on our Canadian crude oil waterflood properties and $24.3 million on our Marcellus natural gas assets.

We recorded net divestment proceeds of $670.4 million in 2016. In Canada, we sold properties consisting mainly of natural gas assets, which included certain Deep Basin natural gas properties and non-core properties in northwest Alberta with combined production of approximately 8,500 BOE/day. On December 30, 2016, we closed the sale of our non-operated assets in North Dakota with production of approximately 5,000 BOE/day for proceeds of $392.0 million. Through our capital program in 2016 we added 43 MMBOE of gross proved plus probable reserves, replacing 126% of our 2016 production, before accounting for acquisitions and divestments.

Property and land acquisitions in 2016 totaled $126.1 million, largely due to our acquisition of a Canadian waterflood property for a purchase price of $110.3 million, net of closing adjustments.

2019 Guidance

Our capital spending guidance for 2019 is between $565 million and $635 million, and is expected to deliver annual liquids production growth of 9%. Our spending is focused on our core areas, with approximately $480 million allocated to North Dakota, $45 million to our Marcellus gas properties, $45 million to our Canadian crude oil waterflood properties, and $30 million allocated to the DJ Basin. 

Gain on Asset Sales and Note Repurchases

Under full cost accounting rules, divestments of oil and natural gas properties are generally accounted for as adjustments to the full cost pool with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would significantly alter the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized.  No gains or losses were recorded on asset sales in 2018. We recorded gains of $78.4 million during 2017 related to the divestment of our Brooks waterflood property and Canadian shallow gas assets. In 2016, a gain of $559.2 million was recorded on asset divestments, which included a gain of $339.4 million on the fourth quarter sale of our non-operated North Dakota property. Gains and losses are evaluated on a case by case basis for each asset sale, and future sales may or may not result in such treatment.

During 2018 and 2017 we did not repurchase any of our senior notes. During the first half of 2016, we recorded a total gain of $19.3 million on the repurchase of US$267 million of outstanding senior notes at prices between 90% of par and par value. 

Depletion, Depreciation and Accretion (“DD&A”)

 

 

 

 

 

 

 

 

 

 

($ millions, except per BOE amounts)

    

2018

    

2017

    

2016

DD&A expense

 

$

304.3

 

$

250.8

 

$

329.0

Per BOE

 

$

8.94

 

$

8.11

 

$

9.65

 

DD&A of property, plant and equipment (“PP&E”) is recognized using the unit‑of‑production method based on proved reserves. Total DD&A in 2018 increased from 2017 mainly due to a 10% percent increase in overall production. On a per BOE basis, DD&A for 2018 increased as  a result of higher capital spending and additional future development capital associated with undeveloped reserve additions. In 2017, DD&A decreased from the prior year mostly due to asset impairments recorded during 2016 under the U.S. GAAP full cost ceiling test methodology.

Impairments

PP&E

 

 

 

 

 

 

 

 

 

 

 

($ millions)

    

2018

    

2017

    

2016

Canada cost centre

 

$

 —

 

$

 —

 

$

89.4

U.S. cost centre

 

 

 —

 

 

 —

 

 

211.8

Total Impairments

 

$

 —

 

$

 —

 

$

301.2

 

Under U.S. GAAP, the full cost ceiling test is performed on a country‑by‑country cost centre basis using estimated after‑tax future net cash flows discounted at 10% from proved reserves (“Standardized Measure”), using constant prices as defined by the U.S. Securities and Exchange Commission (“SEC”). SEC constant prices are calculated as the unweighted average of the trailing twelve first‑day‑of‑the‑month commodity prices. Standardized Measure is not related to our capital spending investment criteria and is not a fair value-based measurement, but rather a prescribed accounting calculation. Under U.S. GAAP impairments are not reversed in future periods.

ENERPLUS 2018 FINANCIAL SUMMARY              17

 

 

         

The trailing twelve-month average crude oil and natural gas prices generally improved throughout 2018 and 2017 and no impairments were recorded. In comparison, trailing twelve-month average commodity prices weakened significantly in 2016, resulting in non‑cash impairments totaling $301.2 million (before taxes).

The following table outlines the twelve-month average trailing benchmark prices and exchange rates used in our ceiling test at December 31, 2018, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WTI Crude Oil

 

Exchange Rate

 

Edm Light Crude

 

U.S. Henry Hub

 

AECO Natural Gas

Year

 

US$/bbl

 

US/CDN

 

CDN$/bbl

 

Gas US$/Mcf

 

Spot CDN$/Mcf

2018

 

$

65.56

 

1.28

 

$

69.58

 

$

3.10

 

$

1.67

2017

 

$

51.34

 

1.30

 

$

63.57

 

$

2.98

 

$

2.32

2016

 

$

42.75

 

1.32

 

$

52.26

 

$

2.49

 

$

2.17

 

Many factors influence the allowed ceiling value versus our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling tests. For the next year, the primary factors include future first‑day‑of‑the‑month commodity prices, reserves revisions, our capital expenditure levels and timing, acquisition and divestment activity, as well as production levels, which affect DD&A expense.  There is the potential for trailing twelve-month average commodity prices to decline, impacting the ceiling value which could result in non-cash impairments.

Goodwill

Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. We first perform a qualitative assessment of goodwill by evaluating potential indicators of impairment, and if it is more likely than not that the fair value of the reporting unit is less than its carrying value we perform a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings in the Consolidated Statements of Income/(Loss) in the Financial Statements.

Our annual goodwill impairment assessments at December 31, 2018,  2017, and 2016 resulted in no impairment.  

 

Asset Retirement Obligation

 

In connection with our operations, we incur abandonment, reclamation and remediation costs related to assets, such as surface leases, wells, facilities and pipelines. Total asset retirement obligations included on our balance sheet are based on management’s estimate of our net ownership interest, costs to abandon, reclaim and remediate and the timing of the costs to be incurred in future periods.

We have estimated the net present value of our asset retirement obligation to be $126.1 million at December 31, 2018, compared to $117.7 million at December 31, 2017. The increase was largely due to an increase in expected remediation and reclamation estimates and a decrease in our weighted average credit-adjusted risk-free rate used to determine the net present value of the liability. See Note 8 to the Financial Statements for further information.

We take an active approach to managing our abandonment, reclamation and remediation obligations. During 2018, we spent $11.3 million (2017 – $12.9 million) on our asset retirement obligations and we expect to spend approximately $12.0 million in 2019. The majority of our abandonment, reclamation and remediation costs are expected to be incurred between 2025 and 2055. We do not reserve cash or assets for the purpose of funding our future asset retirement obligations. Any abandonment, reclamation and remediation costs are anticipated to be funded out of cash flow and available credit facilities.  

 

Income Taxes

 

 

 

 

 

 

 

 

 

 

($ millions)

    

2018

    

2017

    

2016

Current tax expense/(recovery)

 

$

(27.1)

 

$

(48.0)

 

$

(2.4)

Deferred tax expense/(recovery)

 

 

130.3

 

 

129.9

 

 

(234.8)

Total tax expense/(recovery)

 

$

103.2

 

$

81.9

 

$

(237.2)

 

Our current tax recovery in 2018 was $27.1 million compared to $48.0 in 2017. The recoveries primarily related to the reclassification of AMT refunds from our deferred income tax asset in the amounts of $27.2 million and $50.1 million, respectively. The remaining $27.2 million in AMT refunds are expected to be reclassified to current tax in 2019 and 2020. 

 

 

 

 

18               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

The total tax expense in 2018 was $103.2 million compared to $81.9 in 2017 primarily due to higher overall income in 2018. The deferred tax expense in 2017 included $46.2 million from the remeasurement of our U.S. deferred income tax assets for the federal income tax rate reduction from 35% to 21% after enactment of the U.S. Tax Cuts and Jobs Act, offset by the reversal of the valuation allowance previously recorded on our AMT refund. We assess the recoverability of our deferred income tax assets each period to determine whether it is, more likely than not, all or a portion of our deferred income tax assets will be realized. We consider available positive and negative evidence including future taxable income and reversing existing temporary differences in making this assessment. Our overall deferred income tax asset, net of valuation allowance, was $465.1 million as at December 31, 2018 (2017 - $569.9 million). Our remaining valuation allowance is primarily related to our net capital loss carryforward balance. We do not anticipate future capital gains that will allow us to utilize these losses.

Our estimated tax pools at December 31, 2018 are as follows:

 

 

 

 

Pool Type  ($ millions)

    

2018

Canada

 

 

 

Canadian oil and gas property (“COGPE”)

 

$

 6

Canadian development expenditures (“CDE”)

 

 

91

Canadian exploration expenditures (“CEE”)

 

 

238

Undepreciated capital costs (“UCC”)

 

 

149

Non-capital losses and other credits

 

 

428

 

 

$

912

U.S.

 

 

 

Alternative minimum tax credit (“AMT”)

 

$

58

Net operating losses

 

 

1,052

Depletable and depreciable assets

 

 

870

 

 

$

1,980

Total tax pools and credits

 

$

2,892

Capital losses

 

$

1,226

 

 

LIQUIDITY AND CAPITAL RESOURCES

There are numerous factors that influence how we assess our liquidity and leverage, including commodity price cycles, capital spending levels, acquisition and divestment plans, hedging, share repurchases and dividend levels. We also assess our leverage relative to our most restrictive debt covenant, which is a maximum senior debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. Our senior debt to adjusted EBITDA ratio decreased to 0.9x at December 31, 2018 from 1.2x at December 31, 2017 as a result of an increase in our trailing twelve-month EBITDA, which benefited from increased revenue in 2018. Our net debt to adjusted funds flow ratio improved to 0.4x at December 31, 2018 from 0.6x at December 31, 2017 as a result of the significant increase in our adjusted funds flow in 2018. Although it is not included in our debt covenants, the net debt to adjusted funds flow ratio is often used by investors and analysts to evaluate our liquidity.

Total debt, net of cash at December 31, 2018 increased slightly to $333.5 million compared to $325.8 million at December 31, 2017. Total debt was comprised of $696.8 million in senior notes less $363.3 million in cash. The increase compared to the prior year was a result of the impact of a weaker Canadian dollar at December 31, 2018 on our U.S. dollar denominated senior notes, which more than offset a $16.8 million increase in cash. Our next scheduled senior note repayments of $30 million and US$22 million are due in May and June 2019, respectively, with remaining maturities extending to 2026. At December 31, 2018, we were undrawn on our $800 million bank facility.

Our adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by adjusted funds flow, was 84% for 2018 compared to 93% in 2017. After adjusting for net acquisition and divestment proceeds, our funding surplus for the year ended December 31, 2018 was $104.9 million compared to $77.2 million in 2017. A portion of the funding surplus in 2018 was used to return approximately $79.0 million of capital to shareholders through repurchasing 5,925,084 common shares under the NCIB at an average price of $13.33 per share.  The Company also paid $29.3 million in dividends in 2018. We expect to continue to pay monthly dividends to our shareholders of $0.01 per share, however, if economic conditions change we may make adjustments.

Our working capital deficiency, excluding cash and cash equivalents and current derivative assets and liabilities, increased to $143.1 million at December 31, 2018 from $107.6 million at December 31, 2017. We expect to finance our working capital deficit and our ongoing working capital requirements through cash, adjusted funds flow and our bank credit facility. In addition, we have sufficient liquidity to meet our financial commitments for the near term, as disclosed under “Commitments” below.

 

 

ENERPLUS 2018 FINANCIAL SUMMARY              19

 

 

         

During the fourth quarter, we completed a one-year extension of our $800 million senior, unsecured, covenant‑based bank credit facility, which now matures on October 31, 2021. There were no significant amendments to the agreement terms or debt covenants. Drawn fees on our bank credit facility range between 125 and 315 basis points over Banker’s Acceptance rates, with current drawn fees of 125 basis points over Banker’s Acceptance rates based on our current reported senior net debt to adjusted EBITDA ratio. The bank credit facility ranks equally with our senior unsecured covenant‑based notes.

At December 31, 2018 we were in compliance with all covenants under our bank credit facility and outstanding senior notes. Our bank credit facility and senior note purchase agreements have been filed as material documents on our SEDAR profile at www.sedar.com.   

The following table lists our financial covenants at December 31, 2018:

 

 

 

 

 

Covenant Description

    

 

    

December 31, 2018

Bank Credit Facility:

 

Maximum Ratio

 

 

Senior debt to adjusted EBITDA  ( 1)

 

3.5x

 

0.9x

Total debt to adjusted EBITDA  ( 1)

 

4.0x

 

0.9x

Total debt to capitalization

 

50%

 

19%

 

 

 

 

 

Senior Notes:

 

Maximum Ratio

 

 

Senior debt to adjusted EBITDA  ( 1)(2)

 

3.0x – 3.5x

 

0.9x

Senior debt to consolidated present value of total proved reserves  ( 3)

 

60%

 

21%

 

 

 

 

 

 

 

Minimum Ratio

 

 

Adjusted EBITDA to interest (1)

 

4.0x

 

21.3x

 

Definitions

“Senior Debt” is calculated as the sum of drawn amounts on our bank credit facility, outstanding letters of credit and the principal amount of senior notes.

“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, and other non‑cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve-month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the three months and the trailing twelve months ended December 31, 2018 were $209.7 million and $782.8 million, respectively.

“Total Debt” is calculated as the sum of senior debt plus subordinated debt. Enerplus currently does not have any subordinated debt.

“Capitalization” is calculated as the sum of total debt and shareholder’s equity plus a $1.1 billion adjustment related to our adoption of U.S. GAAP.

 

Footnotes

(1)

See “Non-GAAP Measures” in this MD&A for a reconciliation of adjusted EBITDA to net income.

(2)

Senior debt to adjusted EBITDA for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x.

(3)

Senior debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted at 10%.

 

Counterparty Credit

OIL AND NATURAL GAS SALES COUNTERPARTIES

Our oil and natural gas receivables are with customers in the oil and gas industry and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous purchasers under normal industry sale and payment terms. A credit review process is in place to assess and monitor our counterparties’ creditworthiness on a regular basis. This process involves reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted, we obtain financial assurances such as letters of credit, parental guarantees or third-party insurance to mitigate a portion of our credit risk. This process is utilized for both our oil and natural gas sales counterparties as well as our financial derivative counterparties.

FINANCIAL DERIVATIVE COUNTERPARTIES

We are exposed to credit risk in the event of non‑performance by our financial counterparties regarding our derivative contracts. We mitigate this risk by entering into transactions with major financial institutions, the majority of which are members of our bank syndicate. We have International Swaps and Derivatives Association (“ISDA”) agreements in place with the majority of our financial counterparties. These agreements provide some credit protection by generally allowing parties to aggregate amounts owing to each other under all outstanding transactions and settle with a single net amount in the case of a credit event. To date we have not experienced any losses due to non‑performance by our derivative counterparties. All of our derivative counterparties are considered investment grade. At December 31, 2018, we had $91.5 million in mark-to-market assets offset by $1.9 million of mark‑to‑market liabilities resulting in a net asset position of $89.6 million.  

20               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

Dividends

 

 

 

 

 

 

 

 

 

 

($ millions, except per share amounts)

    

2018

    

2017

    

2016

Cash dividends  ( 1)

 

$

29.3

 

$

29.0

 

$

35.4

Per weighted average share (Basic)

 

$

0.12

 

$

0.12

 

$

0.16

(1)

Excludes changes in non-cash financing working capital. See Note 17(b) of the Consolidated Financial Statements for additional information.

We reported total dividends of $29.3 million or $0.12 per share to our shareholders in 2018. During 2017 and 2016, we reported total dividends of $29.0 million or $0.12 per share and $35.4 million or $0.16 per share, respectively.

Effective for our April 2016 dividend, we reduced our monthly dividend to $0.01 per share from $0.03 per share.

The dividend is part of our strategy to return capital to our shareholders. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

Shareholders’ Capital

 

 

 

 

 

 

 

 

 

 

 

    

2018

    

2017

    

2016

Share capital ($ millions)

 

$

3,337.6

 

$

3,386.9

 

$

3,366.0

 

 

 

 

 

 

 

 

 

 

Common shares outstanding (thousands)

 

 

239,411

 

 

242,129

 

 

240,483

Weighted average shares outstanding – basic (thousands)

 

 

244,076

 

 

241,929

 

 

226,530

Weighted average shares outstanding – diluted (thousands)

 

 

247,261

 

 

247,874

 

 

231,293

 

During 2018, a total of 668,000 shares were issued pursuant to our stock option plan resulting in additional share capital of $9.1 million, and $0.7 million transferred from paid-in capital to share capital (2017 and 2016 – nil). During 2018, a total of 2,539,000 shares were issued pursuant to our treasury‑settled LTI plans and $23.4 million was transferred from paid-in capital to share capital (2017 – 1,646,000 and $21.0 million; 2016 – 594,000 and $9.4 million).

 

On March 21, 2018, Enerplus announced the acceptance of its NCIB by the Toronto Stock Exchange (“TSX”). The bid allows Enerplus to purchase up to 17,095,598 common shares on the TSX, the New York Stock Exchange and/or alternative Canadian trading systems over a period of twelve months commencing on March 26, 2018. All common shares purchased under the bid will be cancelled. During the year ended December 31, 2018, the Company repurchased 5,925,084 common shares under the NCIB at an average price of $13.33 per share, for total consideration of $79.0 million. Of the amount paid, $82.6 million was recorded to share capital and $3.6 million was credited to accumulated deficit. Subsequent to the year, and up to February 20, 2019, the Company repurchased 586,953 common shares under the NCIB at an average price of $11.40 per share, for consideration of $6.7 million.  The Company also received approval from the Board of Directors to renew the NCIB upon expiry of the existing term on March 25, 2019, subject to approval by the TSX.  The proposed renewal will be for 7% of public float (within the meaning under the TSX rules) consistent with the current bid.

 

On May 31, 2016, 33,350,000 common shares were issued at a price of $6.90 per share for gross proceeds of $230.1 million ($220.4 million, net of issue costs before tax).

 

At February 20, 2019, we had 238,824,149 shares outstanding. In addition, an aggregate of 8,599,059 common shares may be issued to settle outstanding grants under the PSU, RSU, and stock option plans, assuming the maximum payout multiplier of 2.0 times for the PSUs.

For further details see Note 13 to the Financial Statements.

 

 

 

ENERPLUS 2018 FINANCIAL SUMMARY              21

 

 

         

Commitments

We have the following minimum annual commitments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

Minimum Annual Commitment Each Year

 

Committed

($ millions)

    

Total

    

2019

    

2020

    

2021

    

2022

    

2023

    

after 2023

Senior notes (1)

 

$

696.8

 

$

60.0

 

$

111.3

 

$

111.3

 

$

109.9

 

$

108.6

 

$

195.7

Transportation commitments (2)

 

 

367.6

 

 

36.8

 

 

37.9

 

 

34.1

 

 

31.4

 

 

30.3

 

 

197.1

Processing commitments

 

 

16.2

 

 

3.5

 

 

3.2

 

 

1.5

 

 

1.5

 

 

1.5

 

 

5.0

Drilling and completions

 

 

51.4

 

 

20.0

 

 

20.0

 

 

11.4

 

 

 —

 

 

 —

 

 

 —

Office lease commitments

 

 

73.7

 

 

9.4

 

 

10.7

 

 

11.2

 

 

11.3

 

 

11.4

 

 

19.7

Sublease recoveries

 

 

(15.4)

 

 

(3.2)

 

 

(3.4)

 

 

(3.2)

 

 

(2.4)

 

 

(1.7)

 

 

(1.5)

Net office lease commitments

 

 

58.3

 

 

6.2

 

 

7.3

 

 

8.0

 

 

8.9

 

 

9.7

 

 

18.2

Total commitments (3)(4)

 

$

1,190.3

 

$

126.5

 

$

179.7

 

$

166.3

 

$

151.7

 

$

150.1

 

$

416.0

(1)

Interest payments have not been included.

(2)

Includes additional firm transportation commitments executed subsequent to year-end.

(3)

Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

(4)

US$ commitments have been converted to CDN$ using the December 31, 2018 foreign exchange rate of 1.3637.

 

In the Marcellus, we have firm transportation agreements in place for approximately 66,000 Mcf/day, which expire between 2020 and 2036. This includes an agreement for firm pipeline capacity on the Tennessee Gas Pipeline from our Marcellus producing region to downstream connections for 30,000 Mcf/day of natural gas until mid-2027, reducing to 15,000 Mcf/day for an additional 9 years, with a total estimated transportation commitment of US$90.4 million through 2036. We have also entered into a binding contract for five years of firm transportation capacity for 30,000 Mcf/day on the PennEast pipeline project. This project has been approved by the Federal Energy Regulatory Commission, however, it is currently awaiting state level approvals with an expected in-service date during 2020. In the Bakken region, subsequent to year end, we entered into a multi-year contract for firm pipeline capacity to transport a portion of our crude oil production to the U.S. Gulf Coast. 

In Canada, we have various firm transportation agreements for approximately 3,200 BOE/day of our crude oil and natural gas liquids production in 2019, decreasing to approximately 1,400 BOE/day on average from 2020 to 2027. We also have firm natural gas transportation contracts in 2019 for approximately 48,000 Mcf/day. At December 31, 2018, we have firm natural gas liquids fractionation contracts for 1,100 BOE/day through 2027.

Our commitments and contingencies are more fully described in Note 15 to the Financial Statements.

 

 

 

 

 

22               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

SELECTED ANNUAL CANADIAN AND U.S. FINANCIAL RESULTS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended

 

Year ended

 

December 31, 2018

 

December 31, 2017

(millions, except per unit amounts)

    

Canada

    

U.S.

    

Total

    

Canada

    

U.S.

    

Total

Average Daily Production Volumes (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (bbls/day)

 

 

9,282

 

 

36,142

 

 

45,424

 

 

10,779

 

 

26,156

 

 

36,935

Natural gas liquids (bbls/day)

 

 

1,064

 

 

3,422

 

 

4,486

 

 

1,193

 

 

2,665

 

 

3,858

Natural gas (Mcf/day)

 

 

27,497

 

 

232,340

 

 

259,837

 

 

46,228

 

 

217,278

 

 

263,506

Total average daily production (BOE/day)

 

 

14,929

 

 

78,287

 

 

93,216

 

 

19,677

 

 

65,034

 

 

84,711

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pricing (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (per bbl)

 

$

55.50

 

$

79.49

 

$

74.59

 

$

51.87

 

$

61.50

 

$

58.69

Natural gas liquids (per bbl)

 

 

45.22

 

 

23.05

 

 

28.31

 

 

38.13

 

 

26.38

 

 

30.01

Natural gas (per Mcf)

 

 

2.90

 

 

3.49

 

 

3.42

 

 

3.30

 

 

3.19

 

 

3.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital spending

 

$

53.3

 

$

540.6

 

$

593.9

 

$

56.5

 

$

401.5

 

$

458.0

Acquisitions

 

 

4.2

 

 

21.6

 

 

25.8

 

 

4.7

 

 

8.6

 

 

13.3

Divestments

 

 

1.2

 

 

(8.1)

 

 

(6.9)

 

 

(56.6)

 

 

0.4

 

 

(56.2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Netback (3) Before Hedging

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

$

237.9

 

$

1,373.0

 

$

1,610.9

 

$

276.3

 

$

865.5

 

$

1,141.8

Royalties

 

 

(39.6)

 

 

(278.6)

 

 

(318.2)

 

 

(49.3)

 

 

(171.8)

 

 

(221.1)

Production taxes

 

 

(3.1)

 

 

(84.2)

 

 

(87.3)

 

 

(3.3)

 

 

(51.0)

 

 

(54.3)

Cash operating expenses

 

 

(75.2)

 

 

(163.1)

 

 

(238.3)

 

 

(82.1)

 

 

(115.6)

 

 

(197.7)

Transportation costs

 

 

(11.4)

 

 

(112.1)

 

 

(123.5)

 

 

(13.3)

 

 

(98.0)

 

 

(111.3)

Netback before hedging

 

$

108.6

 

$

735.0

 

$

843.6

 

$

128.3

 

$

429.1

 

$

557.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative instruments loss/(gain)

 

$

(88.2)

 

$

 —

 

$

(88.2)

 

$

(14.3)

 

$

 —

 

$

(14.3)

General and administrative expense (4)

 

 

43.3

 

 

32.5

 

 

75.8

 

 

48.9

 

 

25.4

 

 

74.3

Current income tax expense/(recovery)

 

 

(0.4)

 

 

(26.7)

 

 

(27.1)

 

 

(0.4)

 

 

(47.6)

 

 

(48.0)

(1)

Company interest volumes.

(2)

Before transportation costs, royalties and the effects of commodity derivative instruments.

(3)

See “Non‑GAAP Measures” section in this MD&A.

(4)

Includes share‑based compensation.

THREE YEAR SUMMARY OF KEY MEASURES

 

 

 

 

 

 

 

 

 

($ millions, except per share amounts)

2018

    

2017

    

2016

Oil and natural gas sales, net of royalties

$

1,292.7

 

$

920.7

 

$

722.7

Net income/(loss)

 

378.3

 

 

237.0

 

 

397.4

Per share (Basic)

 

1.55

 

 

0.98

 

 

1.75

Per share (Diluted)

 

1.53

 

 

0.96

 

 

1.72

Adjusted net income (1)

 

344.8

 

 

132.2

 

 

240.2

Cash flow from operating activities

 

738.8

 

 

476.1

 

 

312.3

Adjusted funds flow (1)

 

753.5

 

 

524.1

 

 

305.6

Cash dividends (2)

 

29.3

 

 

29.0

 

 

35.4

Per share (Basic) (2)

 

0.12

 

 

0.12

 

 

0.16

Total assets

 

3,118.3

 

 

2,645.8

 

 

2,638.9

Total debt

 

696.8

 

 

672.4

 

 

768.8

Total debt net of cash (1)

 

333.5

 

 

325.8

 

 

375.5

(1)

See “Non-GAAP Measures” section of this MD&A.

(2)

Calculated based on dividends paid or payable.

ENERPLUS 2018 FINANCIAL SUMMARY              23

 

 

         

2018 versus 2017

Net oil and natural gas sales were $1,292.7 million in 2018 compared to $920.7 million in 2017 due to higher realized commodity prices, increased production and higher crude oil and natural gas liquids weighting in 2018.

We reported net income of $378.3 million in 2018 compared to $237.0 million in 2017. The increase in 2018 was primarily due to increased oil and natural gas sales and higher gains on commodity derivative instruments, which were offset in part by no gains on asset divestments and increased foreign exchange losses compared to 2017.

Cash flow from operating activities and adjusted funds flow increased to $738.8 million and $753.5 million, respectively, in 2018 from $476.1 million and $524.1 million in 2017. The increase was mainly due to a $372.0 million increase in net oil and gas natural gas sales, offset by realized losses on derivative instruments and higher operating expenses and production taxes resulting from higher production.

2017 versus 2016

Net oil and natural gas sales were $920.7 million in 2017 compared to $722.7 million in 2016 due to higher realized commodity prices, offset by the impact of lower production volumes as a result of our asset divestments over that period.

We reported net income of $237.0 million in 2017 compared to $397.4 million in 2016. The decrease in 2017 was primarily due to a $480.8 million decrease in gains being recorded on the divestment of assets during the period and a gain recorded in 2016 for $19.3 million related to the prepayment of senior notes. We also recorded a deferred tax expense of $129.9 million in 2017 compared to a deferred tax recovery of $234.8 million in 2016, due to higher net income before taxes and the impact of the U.S. Tax Legislation on our U.S. deferred income tax assets.

Cash flow from operating activities and adjusted funds flow increased to $476.1 million and $524.1 million, respectively, in 2017 from $312.3 million and $305.6 million in 2016. The increase was mainly due to a $198.0 million increase in net oil and gas natural gas sales, lower operating costs, interest, and cash G&A expenses, offset by lower realized cash gains on commodity hedges. Adjusted funds flow in 2017 benefited from a $50.1 million AMT refund realized in 2018.

QUARTERLY FINANCIAL INFORMATION

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and Natural

 

 

 

 

 

 

 

 

 

 

 

Gas Sales, Net

 

Net

 

Net Income/(Loss) Per Share

($ millions, except per share amounts)

    

of Royalties

    

Income/(Loss)

    

Basic

    

Diluted

2018

 

 

 

 

 

 

 

 

 

 

 

    

Fourth Quarter

 

$

326.7

 

$

249.4

 

$

1.03

 

$

1.02

Third Quarter

 

 

373.6

 

 

86.9

 

 

0.35

 

 

0.35

Second Quarter

 

 

327.4

 

 

12.4

 

 

0.05

 

 

0.05

First Quarter

 

 

265.0

 

 

29.6

 

 

0.12

 

 

0.12

Total 2018

 

$

1,292.7

 

$

378.3

 

$

1.55

 

$

1.53

2017

 

 

 

 

 

 

 

 

 

 

 

 

Fourth Quarter

 

$

271.1

 

$

15.3

 

$

0.06

 

$

0.06

Third Quarter

 

 

196.1

 

 

16.1

 

 

0.07

 

 

0.07

Second Quarter

 

 

225.7

 

 

129.3

 

 

0.53

 

 

0.52

First Quarter

 

 

227.8

 

 

76.3

 

 

0.32

 

 

0.31

Total 2017

 

$

920.7

 

$

237.0

 

$

0.98

 

$

0.96

 

Oil and natural gas sales, net of royalties, increased in 2018 compared to 2017 due to an increase in realized commodity prices and higher production volumes.  Although production levels increased throughout 2018, declining commodity prices during the fourth quarter of 2018 resulted in lower net sales for this period.  

Net income increased to $378.3 million in 2018 due to higher net sales and non-cash gains on commodity derivatives as commodity prices fell during the fourth quarter.

During 2017,  we reported net income of $237.0 million which included a gain of $78.4 million on the divestment of certain Canadian assets during the second quarter.

 

24               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

ENVIRONMENT

We strive to carry out our activities and operations in compliance with all applicable regulations and best industry practices. Our operations are subject to laws and regulations concerning pollution, protection of the environment and the handling of hazardous materials and waste. We set corporate targets and mandates to maintain our strong environmental performance and execute environmental initiatives to become more energy efficient and to reduce, reuse and recycle water and minimize waste.

We have a Safety and Social Responsibility Policy (“S&SR Policy”), which articulates our commitment to health and safety, stakeholder engagement, environmental and regulatory compliance. Our Board of Directors and President & Chief Executive Officer are ultimately accountable for ensuring compliance with the S&SR Policy. The Safety & Social Responsibility Committee of our Board of Directors (the “S&SR Committee”) is responsible for overseeing our S&SR performance, ensuring there are adequate systems in place to support ongoing compliance, and to plan the Company’s activities in a safe and socially responsible manner.

We have established processes and programs designed to evaluate and minimize health, safety, and environmental risks, and strive for continuous improvement in our S&SR performance. We also actively participate in industry recognized programs that support our sustainability goals. 

The S&SR Policy articulates our commitment to protecting the health and safety of all persons and communities involved in, or affected by, our business activities, and articulates our commitment to the environment. It states we endeavor to: (i) proactively manage our impact on the environment and consider innovative improvement opportunities; (ii) work to reduce our environmental impact in the areas in which we operate; (iii) improve our water and land use practices; (iv) limit the waste we generate; (v) prevent and manage environmental releases; (vi) provide transparent disclosure; and (vii) provide resources and training to meet our environmental commitments. Our commitment to building meaningful and transparent relationships, engaging with our stakeholders, and adhering to responsible development of resources and regulatory compliance is also stated.

We intend to continue to improve energy efficiencies and proactively manage our greenhouse gas emissions in compliance with applicable government regulations, including regulations enacted at the provincial, state, and federal levels in which we operate.

There are inherent risks of spills and pipeline leaks at our operating sites and clean‑up costs may be significant. However, we have an active site inspection program, corrosion risk management strategy and asset integrity management program to help minimize this risk. In addition, we carry environmental insurance to help mitigate the cost of releases should they occur.

Some of our operations use hydraulic fracturing techniques, which involves the injection of pressurized fluids, sand, and small amounts of additives into a well bore. Government and regulatory agencies continue to frame regulations related to this process. We believe we are in compliance with all current government regulations and industry best practices in the U.S. and Canada.

The S&SR Committee regularly reviews health, safety, environmental and regulatory updates, and risks. At present, we believe we are, and expect to continue to be, in compliance with all material applicable environmental laws and regulations and we have included appropriate amounts in our capital expenditure budget to continue to meet our ongoing environmental obligations. However, increased capital and operating costs may be incurred if regulations in Canada or the U.S. impose more stringent compliance requirements.

 

We publish a Corporate Sustainability Report in accordance with the Global Reporting Initiative (GRI) international standard. The report summarizes our environmental, safety, social responsibility and governance performance, and can be found on our website at www.enerplus.com .  

 

Overall, we strive to operate in a socially responsible manner and believe our health, safety and environmental initiatives and performance confirm our ongoing commitment to environmental stewardship and the health and safety of our employees, contractors, and the public in the communities in which we operate.

 

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. GAAP requires management to make certain judgments and estimates. Due to the timing of when activities occur compared to the reporting of those activities, management must estimate and accrue operating results and capital spending. Changes in these judgments and estimates could have a material impact on our financial results and financial condition.

ENERPLUS 2018 FINANCIAL SUMMARY              25

 

 

         

Oil and Natural Gas Properties and Reserves

Enerplus follows the full cost method of accounting for oil and natural gas properties. The process of estimating reserves is critical in determining several accounting estimates including the Company’s depletion, ceiling test, valuation allowance on deferred income tax and gain or loss calculations. Estimating reserves requires significant judgments based on available geological, geophysical, engineering and economic data. These estimates may change substantially as data from ongoing development and production activities becomes available, and as economic conditions impacting oil and natural gas prices, operating costs and royalty burdens change. Reserves estimates impact net income through depletion, the determination of asset retirement obligation and the application of impairment tests. Revisions or changes in reserves estimates can have either a positive or a negative impact on net income.

Asset Impairment

Ceiling Test

Under the full cost method of accounting for PP&E, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet by cost centre. If the net capitalized costs of our oil and natural gas properties exceed the cost centre ceiling, we are subject to a ceiling test write‑down to the extent of such excess. These write‑downs reduce net income and impact shareholders’ equity in the period of occurrence and result in lower depletion expense in future periods. The volume and discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12‑month period ending at the balance sheet date. If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that further write‑downs of our oil and natural gas properties could occur in the future. Under U.S. GAAP impairments are not reversed in future periods.

Goodwill

Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net assets acquired. Goodwill is allocated to reporting units and is assessed for impairment at least annually. To assess impairment, the Company first evaluates qualitative factors, such as industry and market considerations and overall financial performance, to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value including goodwill, a quantitative impairment test is performed. If the carrying amount of the reporting unit exceeds its related fair value, goodwill is written down to its implied fair value. The fair value used in the impairment test is based on estimates of discounted future cash flows which involve assumptions of natural gas and liquids reserves, including commodity prices, future costs and discount rates.

Income Taxes

Management makes certain estimates in calculating deferred tax assets and liabilities, as well as income tax expense. These estimates often involve judgment regarding differences in the timing and recognition of revenue and expense for tax and financial reporting purposes as well as the tax basis of our assets and liabilities at the balance sheet date before tax returns are completed. Additionally, we must assess the likelihood we will be able to recover or utilize our deferred tax assets. We must record a valuation allowance against a deferred tax asset where all or a portion of that asset is not expected to be realized. In evaluating whether a valuation allowance should be applied, we consider evidence such as future taxable income, among other factors, both positive and negative. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change, and in particular decrease in a period where we determine it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely than not that the asset will be realized.

 

Asset Retirement Obligation

Management calculates the asset retirement obligation based on estimated costs to abandon, reclaim and remediate its ownership interest in all wells, facilities and pipelines and the estimated timing of the costs to be incurred in future periods. The fair value estimate is capitalized to PP&E as part of the cost of the related asset and depleted over its useful life. There are uncertainties related to asset retirement obligations and the impact on the financial statements could be material as the eventual timing and costs for the obligations could differ from our estimates. Factors that could cause our estimates to differ include any changes to laws or regulations, reserves estimates, costs and technology.

 

26               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

Business Combinations

Management makes various assumptions in determining the fair value of any acquired company’s assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and gas properties. To determine the fair value of these properties, we, and independent evaluators, estimate oil and gas reserves and future prices of crude oil and natural gas.

Derivative Financial Instruments

We utilize derivative financial instruments to manage our exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices, foreign currency exchange rates, interest rates and counterparty credit risk.

RECENT U.S. GAAP ACCOUNTING AND RELATED PRONOUNCEMENTS

Effective in 2018, Enerplus adopted ASC 606 – Revenue from contracts with customers. The adoption of this standard had no impact on the Consolidated Financial Statements, with the exception of additional note disclosures. See Notes 2(o) and 9 to the Consolidated Financial Statements for further details.

Effective January 1, 2019, Enerplus is required to adopt ASC 842 – Leases.   The adoption of this standard is expected to have a material impact on the Company’s Consolidated Financial Statements. See Note 2(o) to the Consolidated Financial Statements for further details.

Refer to Note 2(o) in our Financial Statements for a detailed listing of Standards and Interpretations that were issued but not yet effective at December 31, 2018.

RISK FACTORS AND RISK MANAGEMENT 

Commodity Price Risk

Our operating results and financial condition are dependent on the prices we receive for our crude oil, natural gas liquids, and natural gas production. These prices have fluctuated widely in response to a variety of factors including global and domestic supply and demand of crude oil, natural gas and natural gas liquids, economic conditions including currency fluctuations, weather conditions, the level of consumer demand, the ability to export oil and liquefied natural gas and natural gas liquids from North America and the supply and price of imported oil and liquefied natural gas, the production and storage levels of North American crude oil, natural gas and natural gas liquids, political stability, transportation facilities, availability of processing, fractionation and refining facilities, the effect of world-wide energy conservation and greenhouse gas reduction measures, the price and availability of alternative fuels and existing and proposed changes to government regulations.

A future decline in crude oil or natural gas prices may have a material adverse effect on our operations and cash flows, financial condition, borrowing ability, levels of reserves and resources and the level of expenditures for the development of our oil and natural gas reserves or resources. Certain oil or natural gas wells may become or remain uneconomic to produce if commodity prices are low, thereby impacting our production volumes, or our desire to market our production in unsatisfactory market conditions. Furthermore, we may be subject to the decisions of third party operators or to legislative decisions by regional governments who, independently and using different economic parameters, may decide to curtail or shut-in jointly owned production or to mandate industry-wide production curtailments.

We may use financial derivative instruments and other hedging mechanisms to help limit the adverse effects of crude oil, natural gas liquids, and natural gas price volatility. However, we do not hedge all of our production and expect there will always be a portion that remains unhedged. Furthermore, we may use financial derivative instruments that offer only limited protection within selected price ranges. To the extent price exposure is hedged, we may forego the benefits that would otherwise be experienced if commodity prices increase. At February 20, 2019, approximately 63% of our 2019 forecasted crude oil production, net of royalties, and 34% of our 2019 forecasted natural gas production, net of royalties, are hedged at price levels disclosed in the “Price Risk Management” section above. For 2020 we have also hedged approximately 43%, of our forecasted 2019 crude oil production, net of royalties. Refer to the “Price Risk Management” section for further details on our price risk management program.

 

 

 

 

 

 

ENERPLUS 2018 FINANCIAL SUMMARY              27

 

 

         

Regulatory Risk and Greenhouse Gas Emissions

 

Government royalties, environmental laws and regulatory requirements can have a significant financial and operational impact on us. As an oil and gas producer, we operate under federal, provincial, state, tribal and municipal legislation and regulation that govern such matters as royalties, land tenure, prices, production rates, various environmental protection controls, well and facility design and operation, income taxes, and the exportation of crude oil, natural gas and other products. We may be required to apply for regulatory approvals in the ordinary course of business. To the extent that we fail to comply with applicable government regulations or regulatory approvals, we may be subject to compliance and enforcement actions that are either remedial or punitive to deter future noncompliance. Such actions include fines or fees, notices of noncompliance, warnings, orders, curtailment, administrative sanctions, and prosecution.  

Government regulations may be changed from time to time in response to economic or political conditions, including the election of new state, provincial or federal leaders. Additionally, our entry into new jurisdictions or adoption of new technology may attract additional regulatory oversight which could result in higher costs or require changes to proposed operations. Canadian and U.S. governments have enhanced their oversight and reporting obligations associated with fracturing procedures and increased their scrutiny of the usage and disposal of chemicals and water used in fracturing procedures. Additionally, various levels of Canadian and U.S. governments are considering or have implemented legislation to reduce emissions of greenhouse gases, including volatile organic compounds (“VOC”), and methane gas emissions.

The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations could negatively impact the development of oil and gas properties and assets, reduce demand for crude oil and natural gas or impose increased costs on oil and gas companies including taxes, fees or other penalties.

Although we have no control over these regulatory risks, we continuously monitor changes in these areas by participating in industry organizations, conferences, exchanging information with third party experts and employing qualified individuals to assess the impact of such changes on our financial and operating results. Accordingly, while we continue to prepare to meet the potential requirements at each of the provincial, state and federal levels, the actual cost impact and its materiality to our business remains uncertain.

Access to Transportation and Processing Capacity

Market access for crude oil, natural gas liquids and natural gas production in Canada and the U.S. is dependent on our ability, and the ability of our buyers as applicable, to obtain transportation capacity on third party pipelines and rail as well as access to processing facilities. As production increases in the regions where we operate,  it is possible production may exceed the existing capacity of the gathering, pipeline, processing or rail infrastructure. While third party pipelines, processors and independent rail operators generally expand capacity to meet market needs, there can be differences in timing between the growth of production and the growth of capacity. There are occasionally operational reasons for curtailing transportation and processing capacity. Accordingly, there can be periods where transportation and processing capacity is insufficient to accommodate all the production from a given region, causing added expense and/or volume curtailments for all shippers. Our assets are concentrated in specific regions where government or other third parties could limit or ban the shipping of commodities by truck, pipeline or rail. Special interest groups could also oppose infrastructure development and/or expansion resulting in a delay or even the cancellation of the required infrastructure, further impeding our ability to produce and market our products. Additionally, the transportation of crude oil by rail has been under closer scrutiny by government regulatory agencies in Canada and the U.S. over the past few years. As a result, transporting crude oil by rail may carry a higher cost versus traditional pipeline infrastructure or other means of transporting production.

We monitor this risk for both the short and longer term through dialogue and review with the third party pipelines and other market participants. Where available and commercially appropriate, given the production profile and commodity, we attempt to mitigate transportation and processing risk by contracting for firm pipeline or processing capacity or using other means of transportation, including trucking or selling to third parties that have access to pipeline or rail capacity.

Access to Field Services

Our ability to drill, complete and tie‑in wells in a timely manner may be impacted by our access to service providers and supplies. Activity levels in each area may limit our access to these resources, restricting our ability to execute our capital plans in a timely manner. In addition, field service costs are influenced by market conditions and therefore can become cost prohibitive.

Although we have entered into service contracts for a portion of field services that will secure some of our drilling and fracturing services through 2019, access to field services and supplies in other areas of our business will continue to be subject to market availability.

 

28               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

Risk of Increased Capital or Operating Costs

Higher capital or operating costs associated with our operations will directly impact our capital efficiencies and cash flow. Capital costs of completions, specifically the costs of proppant, and operating costs such as electricity, chemicals, gas processing, supplies, energy services and labour costs, are a few of the costs that are susceptible to material fluctuation. Although we have a portion of our 2019 capital and operating costs protected with existing agreements and contract reopeners, changing regulatory conditions, such as those in the U.S. requiring that certain raw materials be sourced from the U.S., may result in higher than expected supply costs.

Risk of Curtailed or Shut-in Production

Should we be required to curtail or shut‑in production as a result of low commodity prices, environmental regulation, government regulation or third party operational practices, it could result in a reduction to cash flow and production levels and may result in additional operating and capital costs for the well to achieve prior production levels. In addition, curtailments or shut‑ins may cause damage to the reservoir and may prevent us from achieving production and operating levels that were in place prior to the curtailment or shutting‑in of the reservoir. With regard to curtailment, the Government of Alberta announced industry-wide mandatory crude oil production curtailments on December 9, 2018. However, based on our current and anticipated Alberta oil production levels, we are currently exempt from this legislation. Combined with the ongoing volatility in commodity prices, any shortage in pipeline infrastructure in producing regions where we operate may result in discounted prices and an ongoing risk of price-related production curtailments.

Risk of Public Opposition and Activism

The oil and natural gas industry elicits concerns over climate change, as well as general public opposition to the industry. As a result, industry participants such as Enerplus may be subject to increased public activism, as well as extensive environmental regulation. Activist activity may result in increased costs due to delays or damage.

The expansion of our business activities, both geographically and with a focus on exploration, may draw increased attention from shareholder activists who oppose our strategy, which could have an adverse effect on market value. Our ongoing participation in the Canadian and U.S. capital markets may expose us to greater risk of class action lawsuits related to securities law, title, contractual and environmental matters.

Access to Capital Markets

Our access to capital has allowed us to fund a portion of our acquisitions and development capital program through issuance of equity and debt in past years. Continued access to capital is dependent on our ability to optimize our existing assets and to demonstrate the advantages of the acquisition or development program that we are financing at the time, as well as investors’ view of the oil and gas industry overall. We may not be able to access the capital markets in the future on terms favorable to us, or at all. Our continued access to capital markets is dependent on corporate performance and investor perception of future performance (both corporately and for the oil and gas sector in general).

We are required to assess our “foreign private issuer” status under U.S. securities laws on an annual basis. If we were to lose our status as a “foreign private issuer” under U.S. securities laws, we may have restricted access to capital markets for a period of time until the required approvals are in place from the SEC.

Anticipated Benefits of Acquisitions or Divestments

From time to time, we may acquire additional crude oil and natural gas properties and related assets. Achieving the anticipated benefits of such acquisitions will depend in part on successfully consolidating functions and integrating operations, procedures, and personnel in a timely and efficient manner, as well as our ability to realize the anticipated growth opportunities from combining and integrating the acquired assets and properties into our existing business. These activities will require the dedication of substantial management effort, time, capital, and other resources, which may divert management's focus, capital and other resources from other strategic opportunities and operational matters during this process. The risk factors specified in this MD&A relating to the crude oil and natural gas business and our operations, reserves and resources apply equally to future properties or assets that we may acquire. We conduct due diligence in connection with acquisitions, but there is no assurance that we will identify all the potential risks and liabilities related to such properties.

 

 

 

 

 

 

 

 

ENERPLUS 2018 FINANCIAL SUMMARY              29

 

 

         

When acquiring assets, we are subject to inherent risks associated with predicting the future performance of those assets. We may make certain estimates and assumptions respecting the characteristics of the assets we acquire, that may not be realized over time. As such, assets acquired may not possess the value we attribute to them, which could adversely impact our future cash flows. To the extent that we make acquisitions with higher growth potential, the higher risks often associated may result in increased chances that actual results may vary from our initial estimates. An initial assessment of an acquisition may be based on a report by engineers or firms of engineers that have different evaluation methods, approaches, and assumptions than those of our engineers, and these initial assessments may differ significantly from our subsequent assessments. There is also no assurance that the acquired assets will be viewed favourably by our investors and could result in a negative effect to the price of our common shares.

 

Certain acquisitions, and in particular acquisitions of higher risk/higher growth assets and the development of those acquired assets, may require capital expenditures and we may not receive cash flow from operating activities from these acquisitions for several years, or in amounts less than anticipated. Accordingly, the timing and amount of capital expenditures may adversely affect our cash flow.

 

We may also seek to divest of properties and assets from time to time. These divestments may consist of non‑core properties or assets, or may consist of assets or properties that are being monetized to fund alternative projects or development or debt repayments. There can be no assurance that we will be successful, that we will realize the amount of desired proceeds, or that such divestments will be viewed positively by the financial markets. Divestments may negatively affect our results of operations or the trading price of our common shares. In addition, although divestments typically transfer future obligations to the buyer, we may not be exempt from certain future obligations, including abandonment, reclamation, and/or remediation if applicable, which may have an adverse effect on our operations and financial condition.

Changes in Income Tax and Other Laws

Income tax, other laws or government incentive programs relating to the oil and gas industry may change in a manner that adversely affects us or our security holders. Canadian, U.S. and foreign tax authorities may interpret applicable tax laws, tax treaties or administrative positions differently than we do or may disagree with how we calculate our income for tax purposes in a manner which is detrimental to us and our security holders.

We monitor developments with respect to pending legal changes and work with the industry and professional groups to ensure that our concerns with any changes are made known to various government agencies. We obtain confirmation from independent legal counsel and advisors with respect to the interpretation and reporting of material transactions.

Health, Safety and Environmental Risk

Health, safety and environmental risks impact our workforce and operating costs and result in the enhancement of our business practices and standards. There may be risks associated with hydraulic fracturing or produced water disposal including the risk of induced seismicity with the injection of fluid into any reservoir. We expect regulatory frameworks will be amended or continue to emerge in this regard. Although Enerplus proactively mitigates perceived risks involved in the hydraulic fracturing process, increased capital and operating costs may be incurred if regulations in Canada or the U.S. impose more stringent compliance requirements surrounding hydraulic fracturing. The impact of such changes on our business could increase our cost of compliance and the risk of litigation and environmental liability.

We have an S&SR department that develops standards and systems to manage health, safety and environmental risks, and regulatory compliance. The S&SR Committee of our Board of Directors is responsible for overseeing the organization’s health, safety and environmental performance and ensuring there are adequate systems in place to support ongoing compliance, and to plan activities in a safe and socially responsible manner. We have insurance to cover a portion of our property losses, liability and business interruption. At present, we believe we are, and expect to continue to be, in compliance with all material applicable environmental laws and regulations and have included appropriate amounts in our capital expenditure budget to continue to meet our ongoing environmental obligations.

Production Replacement Risk

Oil and natural gas reserves naturally deplete as they are produced over time. Our ability to replace production depends on our success in acquiring new land, reserves and/or resources and developing existing reserves and resources. Acquisitions of oil and gas assets will depend on our assessment of value at the time of acquisition and ability to secure the acquisitions generally through a competitive bid process.

Acquisitions and our development capital program are subject to investment guidelines, due diligence and review. Major acquisitions and our annual capital development budget are approved by the Board of Directors and where appropriate, independent reserve engineer evaluations are obtained.

30               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

Oil and Gas Reserves and Resources Risk

The value of our company is based on, among other things, the underlying value of our oil and gas reserves and resources. Geological and operational risks along with product price forecasts can affect the quantity and quality of reserves and resources and the cost of ultimately recovering those reserves and resources. Lower crude oil, natural gas liquids, and natural gas prices along with lower development capital spending associated with certain projects may increase the risk of write‑downs for our oil and gas property investments. Changes in reporting methodology as well as regulatory practices can result in reserves or resources write‑downs.

Each year, independent reserves engineers evaluate the majority of our proved and probable reserves as well as evaluate or audit the resources attributable to a significant portion of our undeveloped land. All reserves information, including our U.S. reserves, has been prepared in accordance with NI 51‑101 standards. For U.S. GAAP accounting purposes, our proved reserves are estimated to be technically the same as our proved reserves prepared under NI 51‑101 and have been adjusted for the effects of SEC constant prices. Independent reserves evaluations have been conducted on approximately 95% of the total proved plus probable net present value (discounted at 10% and using NI 51-101 standards) of our reserves at December 31, 2018. McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated 70% of our Canadian reserves and reviewed the internal evaluation completed by Enerplus on the remaining portion. McDaniel also evaluated 100% of the reserves associated with our U.S. tight oil assets. Netherland, Sewell & Associates, Inc. (“NSAI”) evaluated 100% of our U.S. Marcellus shale gas assets.

The evaluations of contingent resources associated with a portion of our Canadian waterflood properties and our North Dakota assets were conducted by Enerplus’ qualified reserves evaluators and audited by McDaniel. NSAI evaluated our Marcellus shale gas best estimate development pending contingent resources.

The Reserves Committee of the Board of Directors and the Board of Directors has reviewed and approved the reserves and resources reports of the independent evaluators.

Cyber Security Risks

We are subject to a variety of information technology and system risks as part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach and destruction or interruption of our information technology systems by third parties or insiders. Although we have security measures and controls in place that are designed to mitigate these risks, a breach of our security and/or a loss of information could occur and result in a loss of material and confidential information, reputation damage, a breach in privacy laws and disruption to business activities. The significance of any such event is difficult to quantify, but may be material in certain circumstances and could have a material effect on our business, financial condition and results of operations.

Risk of Impairment of Oil and Gas Properties, Deferred Tax Assets and Goodwill

Under U.S. GAAP, the net capitalized cost of oil and gas properties, net of deferred income taxes, is limited to the present value of after‑tax future net revenue from proved reserves, discounted at 10%, and based on the unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the issuer’s reporting date. The amount by which the net capitalized costs exceed the discounted value will be charged to net income.

Under U.S. GAAP, the net deferred tax asset is limited to the estimate of future taxable income resulting from existing properties. We estimate future taxable income based on before‑tax future net revenue from proved plus probable reserves, undiscounted, using forecast prices, and adjusted for other significant items affecting taxable income. The amount by which the gross deferred tax assets exceed the estimate of future taxable income will be charged to net income, however these amounts can be reversed in future periods if future taxable income increases.

 

Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that goodwill may be impaired. We first perform a qualitative assessment by evaluating potential indicators of impairment, and if it is more likely than not that the fair value of the reporting unit is less than its carrying value, a quantitative impairment test is performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to net income.

 

We recorded no impairment on our crude oil and natural gas assets in 2018 and 2017. Similarly, no impairment was recognized on our goodwill and deferred tax asset in 2018 and 2017. There is a risk of impairment on our oil and gas properties, deferred tax asset and goodwill if commodity prices weaken, costs increase, or if there is a downward revision to reserves. Please refer to the “Impairments” and “Income Taxes” sections of the MD&A and Notes 5 and 12 of the Financial Statements for further details.

ENERPLUS 2018 FINANCIAL SUMMARY              31

 

 

         

Counterparty and Joint Venture Credit Exposure

We are subject to the risk that the counterparties to our risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements as a result of liquidity requirements or insolvency. Low oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure of our counterparties to perform their financial or operational obligations may adversely affect our operations and financial position. In addition to the usual delays in payment by purchasers of crude oil and natural gas, payments may also be delayed by, among other things: (i) capital or liquidity constraints experienced by our counterparties, including restrictions imposed by lenders; (ii) accounting delays or adjustments for prior periods; (iii) delays in the sale or delivery of products or delays in the connection of wells to a gathering system; (iv) weather related delays, such as freeze‑offs, flooding and premature thawing; (v) blow‑outs or other accidents; or (vi) recovery by the operator of expenses incurred in the operation of the properties or the establishment by the operator of reserves for these expenses. Any of these delays could reduce the amount of our cash flow and the payment of cash dividends to our shareholders in a given period and expose us to additional third-party credit risks.

 

A credit review process is in place to assess and monitor our counterparties’ credit worthiness on a regular basis. This includes reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted we attempt to obtain financial assurances such as letters of credit, parental guarantees, or third-party insurance to mitigate our counterparty risk. In addition, we monitor our receivables against a watch list of publicly traded companies that have high debt‑to‑cash flow ratios or fully drawn bank facilities and, where possible, take our production in kind rather than relying on third party operators. In certain instances, we may be able to aggregate all amounts owing to each other and settle with a single net amount.

See the “Liquidity and Capital Resources” section for further information.

Title Defects or Litigation

Unforeseen title defects or litigation may result in a loss of entitlement to production, reserves and resources.

Although we conduct title reviews prior to the purchase of assets these reviews do not guarantee that an unforeseen defect in the chain of title will not arise. We maintain good working relationships with our industry partners; however, disputes may arise from time to time with respect to ownership of rights of certain properties or resources.

Foreign Currency Exposure

We have exposure to fluctuations in foreign currency as most of our senior notes are denominated in U.S. dollars. Our U.S. operations are directly exposed to fluctuations in the U.S. dollar when translated to our Canadian dollar denominated financial statements. We also have indirect exposure to fluctuations in foreign currency as our crude oil sales and a portion of our natural gas sales are based on U.S. dollar indices. Our oil and gas revenues are positively impacted when the Canadian dollar weakens relative to the U.S. dollar. However, our U.S. capital spending, transportation and operating costs, interest expense and U.S. dollar denominated debt are negatively impacted with a weak Canadian dollar.

Currently, we do not have any foreign exchange contracts in place to hedge our foreign exchange exposure. However, we continue to monitor fluctuations in foreign exchange and the impact on our operations.

Ability to Divest Properties

 

Recent regulatory changes in Alberta and Saskatchewan have increased the minimum corporate liability rating required of purchasers of crude oil and natural gas properties. As a result, the potential number of parties able to acquire our non-core assets has been reduced, we may not be able to obtain full value for such assets, or transactions may involve greater risk and complexity. The Supreme Court of Canada’s decision in the Redwater Energy Corporation case may also impact our ability to transfer licences, approvals or permits, and may result in increased costs and delays or require changes to our abandonment of projects and transactions. We also understand that further regulatory changes are being planned in Alberta and British Columbia, which may result in additional factors being considered when evaluating such transactions.   

 

Debt covenants may be exceeded with no ability to negotiate covenant relief

Declines in oil and natural gas prices may result in a significant reduction in earnings or cash flow, which could lead us to increase drawn amounts under the bank credit facility to carry out our operations and fulfill our obligations. Significant reductions to cash flow, significant increases in drawn amounts under the bank credit facility or significant reductions to proved reserves may result in a breach of our debt covenants. If a breach occurs, there is a risk that we may not be able to negotiate covenant relief with one or more of our lenders. Failure to comply with debt covenants or negotiate relief may result in our indebtedness under the bank credit facility and senior note agreements becoming immediately due and payable, which may have a material adverse effect on our operations and financial condition.

32               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

Our most restrictive debt covenant is a maximum senior debt to adjusted EBITDA ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At December 31, 2018, our senior debt to adjusted EBITDA ratio was 0.9x. We routinely review our compliance with covenants based on actual and forecasted results and have the ability to adjust our capital spending levels and dividends or pursue asset divestments and equity issuances to comply with our covenants.

See the “Liquidity and Capital Resources” section for further information.

Interest Rate Exposure

Movements in interest rates and credit markets may affect our borrowing costs and value of investments such as our shares as well as other equity investments.

Currently, we do not have any floating interest rate debt. At December 31, 2018, we were undrawn on our $800 million bank credit facility and our debt consisted of fixed interest rate senior notes.

ADJUSTED FUNDS FLOW SENSITIVITY

The sensitivities below reflect all commodity contracts listed in Note 14 to the Financial Statements and are based on 2019 guidance price leve ls of: WTI - US$50.00/bbl, NYMEX - US$3.00/Mcf and a USD/CDN exchange rate of 1.32. To the extent crude oil and natural gas prices change significantly from current levels, the sensitivities will no longer be relevant.

 

 

 

 

 

 

    

Estimated Effect on

 

 

2019 Adjusted Funds Flow

Sensitivity Table

 

per Share (1)

Increase of US$5.00 per barrel in the price of WTI crude oil

 

$

0.20

Decrease of US$5.00 per barrel in the price of WTI crude oil

 

$

(0.17)

Change of US$0.50 per Mcf in the price of NYMEX natural gas

 

$

0.12

Change of 1,000 BOE/day in production

 

$

0.04

Change of $0.01 in the US/CDN exchange rate

 

$

0.02

Change of 1% in interest rate (2)

 

$

nil

(1)

Calculated using 239.4 million shares outstanding at December 31, 2018.

(2)

There is no impact to adjusted funds flow for an increase in interest rates, as Enerplus is currently undrawn on its floating interest rate bank credit facility and all outstanding senior notes are based on fixed interest rates. 

 

2019 GUIDANCE

A summary of our previously released 2019 guidance is below.

 

 

 

Summary of 2019 Expectations

    

Target

Capital spending

 

$565 - $635 million

Average annual production

 

94,000 – 100,000 BOE/day

Average annual crude oil and natural gas liquids production

 

52,500 – 56,000 bbls/day

Average royalty and production tax rate (% of gross sales, before transportation)

 

25%

Operating expenses

 

$8.00/BOE

Transportation costs

 

$4.00/BOE

Cash G&A expenses

 

$1.50/BOE

 

 

 

 

 

 

2019 Differential/Basis Outlook (1)

 

Target

Average U.S. Bakken crude oil differential (compared to WTI crude oil)

 

US$(4.00)/bbl

Average Marcellus natural gas differential (compared to NYMEX natural gas)

 

US$(0.30)/Mcf

 

(1)

Excludes transportation costs. 

 

 

 

ENERPLUS 2018 FINANCIAL SUMMARY              33

 

 

         

NON‑GAAP MEASURES

The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and therefore may not be comparable with the calculation of similar measures by other entities:

“Netback” is used by Enerplus and is useful to investors and securities analysts in evaluating operating performance of our crude oil and natural gas assets. Netback is calculated as oil and natural gas sales less royalties, production taxes, cash operating expenses and transportation costs.

 

 

 

 

 

 

 

 

 

 

Calculation of Netback

Year ended December 31, 

($ millions)

    

2018

    

2017

    

2016

Oil and natural gas sales, net of royalties

 

$

1,292.7

 

$

920.7

 

$

722.7

Less:

 

 

 

 

 

 

 

 

 

Production taxes

 

 

(87.3)

 

 

(54.3)

 

 

(37.4)

Cash operating expenses (1)

 

 

(238.3)

 

 

(197.7)

 

 

(249.0)

Transportation costs

 

 

(123.5)

 

 

(111.3)

 

 

(107.1)

Netback before hedging

 

$

843.6

 

$

557.4

 

$

329.2

Cash gains/(losses) on derivative instruments

 

 

(35.8)

 

 

8.6

 

 

80.3

Netback after hedging

 

$

807.8

 

$

566.0

 

$

409.5

(1)

Total operating expenses have been adjusted to exclude non‑cash gains of nil in 2018, $0.6 million in 2017, and $1.1 million in 2016.

“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non‑cash operating working capital.

 

 

 

 

 

 

 

 

 

 

Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow

Year ended December 31, 

($ millions)

    

2018

    

2017

    

2016

Cash flow from operating activities

 

$

738.8

 

$

476.1

 

$

312.3

Asset retirement obligation expenditures

 

 

11.3

 

 

12.9

 

 

8.4

Changes in non-cash operating working capital

 

 

3.4

 

 

35.1

 

 

(15.1)

Adjusted funds flow

 

$

753.5

 

$

524.1

 

$

305.6

 

“Free cash flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Free cash flow is calculated as adjusted funds flow minus capital spending.

 

 

 

 

 

 

 

 

 

 

Calculation of Free Cash Flow

Year ended December 31, 

($ millions)

    

2018

    

2017

    

2016

Adjusted funds flow

 

$

753.5

 

$

524.1

 

$

305.6

Capital spending

 

 

(593.9)

 

 

(458.0)

 

 

(209.1)

Free cash flow

 

$

159.6

 

$

66.1

 

$

96.5

 

“Adjusted net income”  is used by Enerplus and is useful to investors and securities analyst in evaluating the financial performance of the company by understanding the impact of certain non-cash items and other items that the company considers appropriate to adjust given the irregular nature and relevance to comparable companies. Adjusted net income is calculated as net income adjusted for unrealized derivative instrument gain/loss, asset impairment, gain on divestment of assets, gain on prepayment of senior notes, unrealized foreign exchange gain/loss, and the tax effect of these items.

 

 

 

 

 

 

 

 

 

 

Calculation of Adjusted Net Income

Year ended December 31, 

($ millions)

    

2018

    

2017

    

2016

Net income/(loss)

 

$

378.3

 

$

237.0

 

$

397.4

Unrealized derivative instrument (gain)/loss

 

 

(124.3)

 

 

(6.2)

 

 

105.0

Asset impairment

 

 

 -

 

 

 -

 

 

301.2

Gain on divestment of assets

 

 

 -

 

 

(78.4)

 

 

(559.2)

Gain on prepayment of senior notes

 

 

 -

 

 

 -

 

 

(19.3)

Unrealized foreign exchange (gain)/loss

 

 

58.6

 

 

(42.6)

 

 

(40.6)

Tax effect on above items

 

 

32.2

 

 

22.4

 

 

55.7

Adjusted net income

 

$

344.8

 

$

132.2

 

$

240.2

 

 

34               ENERPLUS 2018 FINANCIAL SUMMARY

 

 

         

“Total debt net of cash” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. Total debt net of cash is calculated as senior notes plus any outstanding bank credit facility balance, minus cash and cash equivalents.

“Net debt to adjusted funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as total debt net of cash divided by a trailing twelve months of adjusted funds flow. This measure is not equivalent to debt to earnings before interest, taxes, depletion, depreciation, amortization, impairment and other non‑cash charges (“adjusted EBITDA”) and is not a debt covenant.

“Adjusted payout ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and liquidity. We calculate our adjusted payout ratio as cash dividends plus capital and office expenditures divided by adjusted funds flow.

 

 

 

 

 

 

 

 

 

 

Calculation of Adjusted Payout Ratio

Year ended December 31, 

($ millions)

    

2018

    

2017

    

2016

Cash dividends

 

$

29.3

 

$

29.0

 

$

35.4

Capital and office expenditures

 

 

600.4

 

 

460.7

 

 

210.6

Sub-total

 

$

629.7

 

$

489.7

 

$

246.0

Adjusted funds flow

 

$

753.5

 

$

524.1

 

$

305.6

Adjusted payout ratio (%)

 

 

84%

 

 

93%

 

 

80%

 

“Adjusted EBITDA” is used by Enerplus and its lenders to determine compliance with financial covenants under its bank credit facility and outstanding senior notes.

 

 

 

 

Reconciliation of Net Income to Adjusted EBITDA (1)

    

 

 

($ millions)

 

December 31, 2018

Net income/(loss)

 

$

378.3

Add:

 

 

 

Interest

 

 

36.8

Current and deferred tax expense/(recovery)

 

 

103.2

DD&A and asset impairment

 

 

304.3

Other non-cash charges (2)

 

 

(39.8)

Adjusted EBITDA

 

$

782.8

(1)

Adjusted EBITDA is calculated based on the trailing four quarters.

(2)

Includes the change in fair value of commodity derivatives, equity swaps, non-cash SBC expense, and unrealized foreign exchange gains/losses.

 

In addition, the Company uses certain financial measures within the “Overview” and “Liquidity and Capital Resources” sections of this MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities. Such measures include “senior debt to adjusted EBITDA”, “senior net debt to adjusted EBITDA”, “total debt to adjusted EBITDA”, “total debt to capitalization”, “maximum debt to consolidated present value of total proved reserves” and “adjusted EBITDA to interest” and are used to determine the Company’s compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of such terms is described under the “Liquidity and Capital Resources” section of this MD&A. 

 

INTERNAL CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures and internal controls over financial reporting as defined in Rule 13a – 15 under the U.S. Securities Exchange Act of 1934 and as defined in Canada under National Instrument 52‑109, Certification of Disclosure in Issuers’ Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Enerplus Corporation have concluded that, as at December 31, 2018, our disclosure controls and procedures and internal control over financial reporting were effective. There were no changes in our internal control over financial reporting during the period beginning on January 1, 2018 and ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  

ADDITIONAL INFORMATION

Additional information relating to Enerplus, including our current Annual Information Form, is available under our profile on the SEDAR website at  www.sedar.com , on the EDGAR website at  www.sec.gov and at  www.enerplus.com .

ENERPLUS 2018 FINANCIAL SUMMARY              35

 

 

         

FORWARD-LOOKING INFORMATION AND STATEMENTS

 

This MD&A contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", “guidance”, "ongoing", "may", "will", "project", "plans", “budget”, "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this MD&A contains forward-looking information pertaining to the following: expected 2019 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; anticipated production volumes subject to curtailment; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management program in 2019 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash G&A, share-based compensation and financing expenses; operating and transportation costs; our anticipated share repurchases under current and future normal course issuer bids; capital spending levels in 2019 and impact thereof on our production levels and land holdings; potential future asset and goodwill impairments, as well as relevant factors that may affect such impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes; future debt and working capital levels and net debt to adjusted funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; expectations regarding our ability to comply with debt covenants under our bank credit facility and outstanding senior notes; our current NCIB and share repurchases thereunder; our future acquisitions and dispositions,  expecting timing thereof and use of proceeds therefrom; and the amount of future cash dividends that we may pay to our shareholders.

 

The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; the availability of third party services; and the extent of our liabilities. In addition, our 2019 guidance contained in this MD&A is based on the following: a WTI price of US$50.00/bbl to US$55.00/bbl, a NYMEX price of US$3.00/Mcf, and a USD/CDN exchange rate of 1.32. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

 

The forward-looking information included in this MD&A is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: continued low commodity prices environment or further volatility in commodity prices; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors, reliance on industry partners and third party service providers; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F as at December 31, 2018).

 

The purpose of our adjusted funds flow sensitivity is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes. The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, and we do not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

36               ENERPLUS 2018 FINANCIAL SUMMARY

EXHIBIT 99.4

 

 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

We consent to the use of our reports, each dated February 22, 2019, with respect to the consolidated balance sheets of Enerplus Corporation as at December 31, 2018 and December 31, 2017, the consolidated statements of income (loss) and comprehensive income (loss), changes in shareholders’ equity and cash flows for the years then ended, and the effectiveness of internal control over financial reporting as of December 31, 2018 included in this annual report on Form 40-F.

 

We also consent to the incorporation by reference of such reports in the Registration Statements (No. 333-200583) on Form S-8 and the Registration Statements (No. 333-216844) on Form-10.

 

 

 

 

 

 

/s/ KPMG LLP

 

Chartered Professional Accountants

 

Calgary, Canada

February 22, 2019

 

EXHIBIT 99.6

 

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

 

 

We hereby consent to the use of our name in the Annual Report on Form 40-F (the "Annual Report") of Enerplus Corporation (the "Registrant").  We hereby further consent to the inclusion in the Annual Report of the Registrant's Annual Information Form dated February 22, 2019 for the year ended December 31, 2018 which document makes reference to our firm and our report dated February 18, 2019 evaluating the Registrant's shale gas and contingent resources interests effective December 31, 2018.

 

 

 

 

Dallas, Texas, U.S.A.

February 20, 2019

NETHERLAND, SEWELL & ASSOCIATES, INC.

 

 

 

 

/s/ C.H. (Scott) Rees III

 

C.H. (Scott) Rees III, P.E.

 

Chairman and Chief Executive Officer

 

EXHIBIT 99.7

CERTIFICATION

I, Ian C. Dundas, certify that:

1.

I have reviewed this Annual Report on Form 40‑F of Enerplus Corporation;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.

The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the issuer and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.

The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

 

 

 

 

 

Date: February 22, 2019

/s/ Ian C. Dundas

 

Ian C. Dundas

 

President and Chief Executive Officer

 

of Enerplus Corporation

 

EXHIBIT 99.8

CERTIFICATION

I, Jodine J. Jenson Labrie, certify that:

1.

I have reviewed this Annual Report on Form 40‑F of Enerplus Corporation;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.

The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the issuer and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.

The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

 

 

 

 

 

Date: February 22, 2019

/s/ Jodine J. Jenson Labrie

 

Jodine J. Jenson Labrie

Senior Vice President and

Chief Financial Officer of Enerplus Corporation

 

EXHIBIT 99.9

 

 

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES‑OXLEY ACT OF 2002

 

 

In connection with the annual report of Enerplus Corporation (the “Corporation”) on Form 40‑F for the fiscal year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ian C. Dundas, President and Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002, that:

 

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

 


President and Chief Executive Officer
of Enerplus Corporation

 

 

/s/ Ian C. Dundas

 

Ian C. Dundas
President and Chief Executive Officer
of Enerplus Corporation

 

 

February 22, 2019

 

The foregoing certification shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of that section. Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the registrant specifically incorporates it by reference.