40-F 1 d345844d40f.htm 40-F 40-F
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2016

 

 

 

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

 

Annual report pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934

 

For the fiscal year ended December 31, 2016

Commission File Number: 001-04307

 

 

Husky Energy Inc.

(Exact name of Registrant as specified in its charter)

 

 

 

Alberta, Canada   1311   Not Applicable

(Province or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number (if applicable))

 

(I.R.S. Employer Identification Number

(if applicable))

707-8th Avenue S.W. Calgary, Alberta, Canada T2P 1H5

(403) 298-6111

(Address and telephone number of Registrant’s principal executive office)

CT Corporation System, 111 Eighth Avenue, New York, New York 10011

(877) 467-3525

(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 Class: None

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

Title of Class: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

Title of Class: Common Shares

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

 

Annual information form   Audited annual financial statements

 

 

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:

1,005,451,854 Common Shares outstanding as of December 31, 2016

10,435,932 Cumulative Redeemable Preferred Shares, Series 1 outstanding as of December 31, 2016

1,564,068 Cumulative Redeemable Preferred Shares, Series 2 outstanding as of December 31, 2016

10,000,000 Cumulative Redeemable Preferred Shares, Series 3 outstanding as of December 31, 2016

8,000,000 Cumulative Redeemable Preferred Shares, Series 5 outstanding as of December 31, 2016

6,000,000 Cumulative Redeemable Preferred Shares, Series 7 outstanding as of December 31, 2016

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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (s.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

 

 

 


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The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the Registrant’s Registration Statement under the Securities Act of 1933: Form F-10 (File No. 333-208443); Form S-8 (File No. 333-187135).

Principal Documents

The following documents have been filed as part of this Annual Report on Form 40-F:

 

A. Annual Information Form

The Annual Information Form (“AIF”) of Husky Energy Inc. (“Husky” or the “Company”) for the year ended December 31, 2016 is included as Document A of this Annual Report on Form 40-F.

 

B. Audited Annual Financial Statements

Husky’s audited consolidated financial statements for the years ended December 31, 2016 and December 31, 2015, including the auditors’ report with respect thereto, is included as Document B of this Annual Report on Form 40-F.

 

C. Management’s Discussion and Analysis

Husky’s Management’s Discussion and Analysis for the year ended December 31, 2016 is included as Document C of this Annual Report on Form 40-F.

Certifications

See Exhibits 31.1, 31.2, 32.1 and 32.2, which are included as Exhibits to this Annual Report on Form 40-F.

Supplemental Reserves Information

See Exhibit 99.1 for the Supplemental Reserves Information, which is included as an Exhibit to this Annual Report on Form 40-F.

Disclosure Controls and Procedures

See the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2016, which is included as Document C of this Annual Report on Form 40-F.

Management’s Annual Report on Internal Control Over Financial Reporting

See the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2016, which is included as Document C of this Annual Report on Form 40-F.

Attestation Report of the Independent Registered Public Accounting Firm

See the “Report of Independent Registered Public Accounting Firm” that accompanies Husky’s audited consolidated financial statements as at and for the years ended December 31, 2016 and 2015, which is included as Document B of this Annual Report on Form 40-F.

Changes in Internal Control Over Financial Reporting

See the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2016, which is included as Document C of this Annual Report on Form 40-F.

Notice Pursuant to Regulation BTR

Not Applicable.

Audit Committee Financial Expert

The Board of Directors of Husky has determined that William Shurniak is an “audit committee financial expert” (as defined in paragraph 8(b) of General Instruction B to Form 40-F) serving on its Audit Committee. Pursuant to paragraph 8(a)(2) of General Instruction B to Form 40-F, the Board has applied the definition of independence applicable to the audit committee members of New York Stock Exchange listed companies, although the Company’s securities are not listed on a U.S. stock exchange. Mr. Shurniak is a corporate director and is independent under the New York Stock Exchange standards. For a description of Mr. Shurniak’s relevant experience in financial matters, see Mr. Shurniak’s history in the section “Directors and Officers” and in the section “Audit Committee” in Husky’s AIF for the year ended December 31, 2016, which is included as Document A of this Annual Report on Form 40-F.

Code of Business Conduct and Ethics

Husky’s Code of Ethics is disclosed in its Code of Business Conduct, which is applicable to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions and to all of its other employees, and is posted on its website at www.huskyenergy.com. A copy of Husky’s Amended


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Code of Business Conduct as in effect during 2016 is incorporated by reference to Exhibit 99.2 to the Company’s Annual Report on Form 40-F for the year ended December 31, 2014 filed on February 27, 2015. In the fiscal year ended December 31, 2016, Husky has not granted a waiver, including an implicit waiver, from a provision of its Code of Ethics to any of its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to one or more of the items set forth in paragraph (9)(b) of General Instruction B to Form 40-F. On February 23, 2017, the Company amended its Code of Business Conduct, effective as of February 24, 2017, and a copy of this new Amended Code of Business Conduct is included as Exhibit 99.2 to this Annual Report on Form 40-F for the fiscal year ended December 31, 2016. In the event that, during Husky’s ensuing fiscal year, Husky:

 

  i. amends any provision of its Code of Business Conduct that applies to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to any element of the code of ethics definition enumerated in paragraph (9)(b) of General Instruction B to Form 40-F; or

 

  ii. grants a waiver, including an implicit waiver, from a provision of its Code of Business Conduct to any of its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to one or more of the items set forth in paragraph (9)(b) of General Instruction B to Form 40-F;

Husky will promptly disclose such occurrences on its website following the date that such amendment or waiver is granted and will specifically describe the nature of any amendment or waiver, and in the case of a waiver, name the person to whom the waiver was granted and the date of the waiver, in each case as further described in paragraph (9) of General Instruction B to Form 40-F.

Principal Accountant Fees and Services

See the section “External Auditor Service Fees” in Husky’s AIF for the year ended December 31, 2016, which is included as Document A of this Annual Report on Form 40-F.

Off-Balance Sheet Arrangements

See the section “Contractual Obligations, Commitments and Off-Balance Sheet Arrangements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2016, which is included as Document C of this Annual Report on Form 40-F.

Tabular Disclosure of Contractual Obligations

See the section “Contractual Obligations, Commitments and Off-Balance Sheet Arrangements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2016, which is included as Document C of this Annual Report on Form 40-F.

Interactive Data File

Not applicable.

Mine Safety Disclosure

Not applicable.


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Undertaking and Consent to Service of Process

Undertaking

Husky 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 in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

Consent to Service of Process

A Form F-X signed by Husky and its agent for service of process has been filed with the Commission together with Form F-10 (File No. 333-208443) in connection with its securities registered on such form.

Any change to the name or address of the agent for service of process of Husky shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of Husky.

Signatures

Pursuant to the requirements of the Exchange Act, Husky Energy Inc. 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.

Dated this 24th day of February, 2017

 

Husky Energy Inc.
By:  

/s/ Robert J. Peabody

  Name: Robert J. Peabody
  Title: President & Chief Executive Officer
By:  

/s/ James D. Girgulis

  Name: James D. Girgulis
  Title: Senior Vice President, General Counsel & Secretary

 


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Document A

Form 40-F

Annual Information Form

For the Year Ended December 31, 2016


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Husky Energy Inc.

Annual Information Form

For the Year Ended December 31, 2016

February 24, 2017


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TABLE OF CONTENTS

 

ADVISORIES

     1  

ABBREVIATIONS AND GLOSSARY OF TERMS

     2  

EXCHANGE RATE INFORMATION

     7  

CORPORATE STRUCTURE

     8  

Husky Energy Inc.

     8  

Intercorporate Relationships

     8  

GENERAL DEVELOPMENT OF HUSKY

     9  

Three-year History of Husky

     9  

DESCRIPTION OF HUSKY’S BUSINESS

     14  

General

     14  

Social and Environmental Policy

     14  

Husky Operational Integrity Management System

     15  

Environmental Protection

     16  

Upstream Operations

     18  

Description of Major Properties and Facilities

     18  

Distribution of Oil and Gas Production

     27  

Disclosures of Oil and Gas Activities

     28  

Oil and Gas Reserves Disclosures

     39  

Infrastructure and Marketing

     58  

Downstream Operations

     60  

U.S. Refining and Marketing

     60  

Upgrading Operations

     60  

Canadian Refined Products

     61  

INDUSTRY OVERVIEW

     64  

RISK FACTORS

     74  

HUSKY EMPLOYEES

     81  

DIVIDENDS

     81  

Dividend Policy and Restrictions

     81  

Common Share Dividends

     81  

Series 1 Preferred Share Dividends

     82  

Series 2 Preferred Share Dividends

     82  

Series 3 Preferred Share Dividends

     82  

Series 5 Preferred Share Dividends

     82  

Series 7 Preferred Share Dividends

     82  

DESCRIPTION OF CAPITAL STRUCTURE

     83  

Common Shares

     83  

Preferred Shares

     83  

Liquidity Summary

     84  

MARKET FOR SECURITIES

     86  

DIRECTORS AND OFFICERS

     89  

Directors

     89  

Officers

     95  

Conflicts of Interest

     95  

Corporate Cease Trade Orders or Bankruptcies

     95  

Individual Penalties, Sanctions or Bankruptcies

     95  

AUDIT COMMITTEE

     96  

External Auditor Service Fees

     96  

LEGAL PROCEEDINGS

     97  

INTEREST OF MANAGEMENT AND OTHERS

     97  

TRANSFER AGENTS

     97  

INTERESTS OF EXPERTS

     97  

ADDITIONAL INFORMATION

     97  

READER ADVISORIES

     98  

Schedule A

     102  

Schedule B

     106  

Schedule C

     107  

Schedule D

     109  


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ADVISORIES

In this AIF, the terms “Husky” and the “Company” mean Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis, including information with respect to predecessor corporations.

Unless otherwise noted, all financial information included and incorporated by reference in this AIF is determined using IFRS as issued by the International Accounting Standards Board.

Except where otherwise indicated, all dollar amounts stated in this AIF are Canadian dollars.

See also “Reader Advisories” at the end of this AIF.

 

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ABBREVIATIONS AND GLOSSARY OF TERMS

When used in this AIF, the following terms have the meanings indicated:

 

Units of Measure

bbl

  

barrel

bbls

  

barrels

bbls/day

  

barrels per calendar day

bcf

  

billion cubic feet

boe

  

barrels of oil equivalent

boe/day

  

barrels of oil equivalent per calendar day

m3

  

cubic metres

GJ

  

gigajoule

long tons/day

  

imperial measurement of a metric tonne per calendar day

mbbls

  

thousand barrels

mbbls/day

  

thousand barrels per calendar day

mboe

  

thousand barrels of oil equivalent

mboe/day

  

thousand barrels of oil equivalent per calendar day

mcf

  

thousand cubic feet

mmbbls

  

million barrels

mmboe

  

million barrels of oil equivalent

mmbtu

  

million British thermal units

mmcf

  

million cubic feet

mmcf/day

  

million cubic feet per calendar day

tcf

  

trillion cubic feet

tCO2e

  

tons of carbon dioxide equivalent

Acronyms

AER

  

Alberta Energy Regulator

AIF

  

Annual Information Form

AQMS

   Air Quality Management System

ARO

  

Asset Retirement Obligations

ASC

  

Alberta Securities Commission

BACT

  

Best Available Control Technology

BLIERs

   Base-Level Industrial Emissions Requirements

CAPP

  

Canadian Association of Petroleum Producers

CAAQS

   Canadian Ambient Air Quality Standards

CFA

  

Canadian Fuels Association

CHOPS

  

Cold Heavy Oil Production with Sand

CKI

   Cheung Kong Infrastructure Holdings Limited

CNOOC

  

China National Offshore Oil Corporation

CO2

  

Carbon dioxide

CO2e

  

Carbon dioxide equivalent

COGEH

  

Canadian Oil and Gas Evaluation Handbook

COSIA

  

Canada’s Oil Sands Innovation Alliance

CSA

  

Canadian Securities Administrators

ECON

   Saskatchewan Ministry of the Economy

EDGAR

  

Electronic Data Gathering, Analysis, and Retrieval system

ELs

  

Exploration Licences

EOR

  

Enhanced Oil Recovery

 

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EPA

  

U.S. Environmental Protection Agency

FASB

  

Financial Accounting Standards Board

FEED

  

Front End Engineering Design

FPSO

  

Floating Production, Storage and Offloading Vessel

GHG

  

Greenhouse Gases

GHGRP

  

Greenhouse Gas Reporting Program

GSA

  

Gas Sales Agreement

HMLP

  

Husky Midstream Limited Partnership

HOA

  

Heads of Agreement

HOIMS

  

Husky Operational Integrity Management System

HSB

  

Husky Synthetic Blend

H2S

  

Hydrogen sulfide

IETA

   International Emissions Trading Association

IFRS

  

International Financial Reporting Standards

IPIECA

  

International Petroleum Industry Environmental Conservation Association

LARP

  

Lower Athabasca Regional Plan

LFEs

   Large Final Emitting Facilities

LMR

   Liability Management Ratio

LNG

  

Liquefied Natural Gas

MBCA

   Migratory Bird Convention Act

MD&A

  

Management’s Discussion and Analysis

NGL

  

Natural Gas Liquids

NIT

  

NOVA Inventory Transfer

NOx

  

Nitrogen Oxide

OPEC

  

Organization of Petroleum Exporting Countries

PAH

   Power Assets Holdings Limited

PSC

  

Production Sharing Contract

REC

  

Reduced Emissions Completions

RFS

  

Renewable fuel standard

RIN

  

Renewable Identification Numbers

RVO

  

Renewable volume obligation

SAGD

  

Steam Assisted Gravity Drainage

SDD

  

Significant Discovery Declaration

SEC

  

Securities and Exchange Commission of the United States

SEDAR

  

System for Electronic Document Analysis and Retrieval

SGS

  

Saskatchewan Gathering System

SO2

  

Sulfur dioxide

TSX

  

Toronto Stock Exchange

U.S.

  

United States

WCS

  

Western Canada Select

WTI

  

West Texas Intermediate

2-D

  

two-dimensional

3-D

  

three-dimensional

The Company uses the terms barrels of oil equivalent (“boe”), which is consistent with other oil and gas companies’ disclosures and is calculated on an energy equivalence basis applicable at the burner tip whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. The term boe is used to express the sum of the total company products in one unit that can be used for comparisons. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is used for consistency with other oil and gas companies and does not represent value equivalency at the wellhead.

Abandonment and reclamation costs

All costs associated with the process of restoring Husky’s properties that have been disturbed by oil and gas activities to a standard imposed by applicable government or regulatory authorities, including costs associated with the retirement of Upstream and Downstream assets which consist primarily of plugging and abandoning wells, abandoning surface and subsea plant, equipment and facilities, and restoring land.

 

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API gravity

Measure of oil density or specific gravity used in the petroleum industry. The API scale expresses density such that the greater the density of the petroleum, the lower the degree of API gravity.

Barrel

A unit of volume equal to 42 U.S. gallons.

Bitumen

Bitumen is a naturally occurring solid or semi-solid hydrocarbon consisting mainly of heavier hydrocarbons with a viscosity greater than 10,000 millipascal-seconds or 10,000 centipoise measured at the hydrocarbon’s original temperature in the reservoir and at atmospheric pressure on a gas-free basis, and that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods.

Canadian Shelf Prospectus

The universal short form base shelf prospectus filed by the Company on February 23, 2015 with applicable securities regulators in each of the provinces of Canada.

Coal bed methane

The primary energy source of natural gas is methane. Coal bed methane is methane found and recovered from the coal bed seams. The methane is normally trapped in coal by water that is under pressure. When the water is removed, the methane is released.

Development well

A well drilled within the proved area of an oil and gas reservoir to the depth of a stratigraphic horizon known to be productive.

Diluent

A lighter gravity liquid hydrocarbon, usually condensate or synthetic oil, added to heavy oil and bitumen to facilitate the transmissibility of the oil through a pipeline.

Enhanced oil recovery

The increased recovery from a crude oil pool achieved by artificial means or by the application of energy extrinsic to the pool. An artificial means or application includes pressuring, cycling, pressure maintenance or injection to the pool of a substance or form of energy but does not include the injection in a well of a substance or form of energy for the sole purpose of aiding in the lifting of fluids in the well, or stimulation of the reservoir at or near the well by mechanical, chemical, thermal or explosive means.

Exploration licence

A licence with respect to the Canadian offshore or the Northwest or Yukon Territories conferring the right to explore for, and the exclusive right to drill and test for, hydrocarbons and petroleum, the exclusive right to develop the applicable area in order to produce petroleum and subject to satisfying the requirements for issuance of a production licence and compliance with the terms of the licence and other provisions of the relevant legislation, the exclusive right to obtain a production licence.

Exploration well

A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas. Generally, an exploration well is any well that is not a development well, a service well, an extension well, which is a well drilled to extend the limits of a known reservoir, or a stratigraphic test well as those terms are defined herein.

Feedstock

Raw materials which are processed into petroleum products.

Field

An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.

Gross/net acres/wells

Gross refers to the total number of acres/wells in which a working interest is owned. Net refers to the sum of the fractional working interests owned by a company.

 

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Gross reserves/production

A company’s working interest share of reserves/production before deduction of royalties.

Heavy crude oil

Crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity.

High-TAN

A measure of acidity. Crude oils with a high content of naphthenic acids are referred to as high total acid number (TAN) crude oils or high acid crude oil. The TAN value is defined as the milligrams of Potassium Hydroxide required to neutralize the acidic group of one gram of the oil sample. Crude oils in the industry with a TAN value greater than one are referred to as High-TAN crudes.

Light crude oil

Crude oil with a relative density greater than 31.1 degrees API gravity.

Liquefied petroleum gas

Liquefied propanes and butanes, separately or in mixtures.

Medium crude oil

Crude oil with a relative density that is greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity.

Natural gas

Natural gas is a naturally occurring hydrocarbon gas mixture consisting primarily of methane, but commonly including varying amounts of other higher alkanes, and sometimes a small percentage of carbon dioxide, nitrogen and/or hydrogen sulfide.

Natural gas liquids

Those hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants, or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butane and condensate or a combination thereof.

Net revenue

Gross revenues less royalties.

Oil sands

Sands and other rock materials that contain bitumen and all other mineral substances in association therewith.

Operating netback

Gross revenue less production, operating and transportation costs, and royalties on a per unit basis.

Petroleum coke

A carbonaceous solid delivered from oil refinery coker units or other cracking processes.

Plan of Development

As it relates to the Company’s operations in Indonesia, a Plan of Development represents development planning on one or more oil and gas fields in an integrated and optimal plan for the production of hydrocarbon reserves considering technical, economical and environments aspects. An initial Plan of Development in a development area needs both SKK Migas and the Minister of Energy and Mineral Resources approval. Subsequent Plans of Development in the same development area only need SKK Migas approval.

Production licence

Confers, with respect to the portions of the offshore area to which the licence applies, the right to explore for, and the exclusive right to drill and test for, petroleum, the exclusive right to develop those portions of the offshore area in order to produce petroleum, the exclusive right to produce petroleum from those portions of the offshore area and title to the petroleum produced.

Production Sharing Contract

A contract for the development of resources under which the contractor’s costs (investment) are recoverable each year out of the production but with a maximum amount of production that can be applied to the cost recovery in any year.

 

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Secondary recovery

Oil or gas recovered by injecting water or gas into the reservoir to force additional oil or gas to the producing wells. Usually, but not necessarily, this is done after the primary recovery phase has passed.

Seismic survey

A method by which the physical attributes in the outer rock shell of the earth are determined by measuring, with a seismograph, the rate of transmission of shock waves through the various rock formations.

Service well

A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation or injection for in-situ combustion.

Spot price

The price for a one-time open market transaction for immediate delivery of a specific quantity of product at a specific location where the commodity is purchased “on the spot” at current market rates.

Steam assisted gravity drainage

An enhanced oil recovery method used to produce heavy crude oil and bitumen in-situ. Steam is injected via a horizontal well along a producing formation. The temperature in the formation increases and lowers the viscosity of the crude oil allowing it to fall into a horizontal production well beneath the steam injection well.

Sulphur

An element that occurs in natural gas and petroleum.

Synthetic oil

A mixture of hydrocarbons derived by upgrading heavy crude oils, including bitumen, through a process that reduces the carbon content and increases the hydrogen content.

Thermal

Use of steam injection into the reservoir in order to enable the heavy oil and bitumen to flow to the well bore.

Turnaround

Performance of plant or facility maintenance.

U.S. Shelf Prospectus

The U.S. universal short form prospectus filed by the Company on December 22, 2015 with the Alberta Securities Commission (“ASC”) and filed as part of a U.S. registration statement on Form F-10 with the U.S. Securities and Exchange Commission (“SEC”).

Waterflood

One method of secondary recovery in which water is injected into an oil reservoir for the purpose of forcing oil out of the reservoir and into the bore of a producing well.

Wellhead

The structure, sometimes called the “Christmas tree”, that is positioned on the surface over a well and used to control the flow of oil or gas as it emerges from the subsurface casing head.

Working interest

A percentage of ownership in an oil and gas lease granting its owners the right to explore, drill and produce oil and gas from a property.

2-D seismic survey

A vertical section of seismic data consisting of numerous adjacent traces acquired sequentially along a straight line.

3-D seismic survey

Three-dimensional seismic imaging which uses a grid of numerous cables rather than a few lines stretched in one line.

 

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EXCHANGE RATE INFORMATION

The following table discloses various indicators of the Canadian dollar/U.S. dollar rate of exchange or the cost of a U.S. dollar in Canadian currency for the three years indicated.

 

     Year ended December 31,  

(Cdn $ per U.S. $)

   2016      2015      2014  

Year-end

     1.343        1.384        1.160  

Low

     1.254        1.173        1.059  

High

     1.459        1.399        1.167  

Average

     1.325        1.279        1.104  

Note: The year-end exchange rates were as quoted by the Bank of Canada for the noon buying rate as at the last day of the relevant period. The high, low and average rates were either quoted or calculated within each of the relevant periods.

 

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CORPORATE STRUCTURE

Husky Energy Inc.

Husky Energy Inc. was incorporated under the Business Corporations Act (Alberta) on June 21, 2000. The Company’s Articles were amended effective February 28, 2011 to permit the issuance of common shares as payment of stock dividends on the common shares and to authorize preferred shares to be issued in one or more series. The Company’s Articles were amended effective March 11, 2011, to create Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”); effective December 4, 2014, to create Cumulative Redeemable Preferred Shares, Series 3 (the “Series 3 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 4 (the “Series 4 Preferred Shares”); effective March 9, 2015, to create Cumulative Redeemable Preferred Shares, Series 5 (the “Series 5 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 6 (the “Series 6 Preferred Shares”); and effective June 15, 2015, to create Cumulative Redeemable Preferred Shares, Series 7 (the “Series 7 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 8 (the “Series 8 Preferred Shares”).

Husky has its registered office and its head and principal office at 707, 8th Avenue S.W., Calgary, Alberta, T2P 1H5.

Intercorporate Relationships

The following table lists Husky’s significant subsidiaries and jointly controlled entities and their place of incorporation, continuance or organization, as the case may be, as at December 31, 2016.(1) All of the following companies and partnerships, except as otherwise indicated, are 100 percent beneficially owned or controlled or directed, directly or indirectly, by Husky.

 

Name

  

Jurisdiction

Subsidiary of Husky Energy Inc.

  

Husky Oil Operations Limited

  

Alberta

Subsidiaries and jointly controlled entities of Husky Oil Operations Limited

  

Husky Oil Limited Partnership

  

Alberta

Husky Terra Nova Partnership

  

Alberta

Husky Downstream General Partnership

  

Alberta

Husky Energy Marketing Partnership

  

Alberta

Husky Energy International Corporation

  

Alberta

Sunrise Oil Sands Partnership (50 percent)

  

Alberta

BP-Husky Refining LLC (50 percent)

  

Delaware

Lima Refining Company

  

Delaware

Husky Marketing and Supply Company

  

Delaware

 

(1) Principal operating subsidiaries exclusive of intercorporate relationships due to financing related receivables and financing investments.

 

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GENERAL DEVELOPMENT OF HUSKY

Three-year History of Husky

The following is a description of how Husky’s business has developed over the last three completed financial years.

2014

On March 17, 2014, the Company issued U.S. $750 million of 4.00 percent notes due April 15, 2024 pursuant to a shelf prospectus and U.S. registration statement. The notes are redeemable at the option of the Company at any time, subject to a make whole premium unless the notes are redeemed in the three month period prior to maturity. Interest is payable semi-annually. The notes are unsecured and unsubordinated and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness.

On June 15, 2014, the Company repaid its maturing 5.90 percent notes. The amount paid to noteholders was U.S. $772 million, including U.S. $22 million of interest, equivalent to $839 million in Canadian dollars at the time of repayment, including interest of $25 million.

On June 19, 2014, the Company’s $1.6 billion revolving syndicated credit facility was increased to $1.63 billion. The maturity, previously set to expire on August 31, 2014, was extended to June 19, 2018. The Company also increased the limit on one of its operating facilities from $50 million to $100 million.

On September 15, 2014, the Company launched a commercial paper program in Canada. The program is supported by the Company’s syndicated credit facilities and the Company is authorized to issue commercial paper up to a maximum of $1.0 billion having a term not to exceed 365 days.

On December 9, 2014, the Company issued 10 million Series 3 Preferred Shares at a price of $25.00 per share for aggregate gross proceeds of $250 million under a shelf prospectus. Holders of the Series 3 Preferred Shares are entitled to receive a cumulative quarterly fixed dividend yielding 4.50 percent annually for the initial period ending December 31, 2019 as declared by the Board of Directors. See “Dividends - Dividend Policy and Restrictions - Series 3 Preferred Share Dividends”.

During 2014, the Company sanctioned three new heavy oil thermal developments in Saskatchewan: 10,000 bbls/day at Edam East, 3,500 bbls/day at Edam West and 10,000 bbls/day at Vawn, and construction work continued at the 10,000 bbls/day Rush Lake heavy oil thermal development.

At the Sunrise Energy Project, steaming commenced in December 2014.

In the Atlantic Region, development drilling had commenced at the South White Rose extension. The Company continued drilling at the North Amethyst Hibernia formation which targeted a secondary deeper zone below the main North Amethyst producing field. In addition, the Company and its partner commenced an 18 month appraisal and exploration drilling program in the Flemish Pass offshore Newfoundland and Labrador, including the area around the Bay Du Nord discovery. Hearings for the public review of the application for a wellhead platform to facilitate full field development at West White Rose were held during 2014. Construction continued on the dry-dock in Argentia, Newfoundland and early site preparation was advanced, including construction of a graving dock.

Development continued at the Ansell liquids rich gas resource play, in west central Alberta, with 31 wells (gross) drilled and 23 wells (gross) completed.

At the Liwan Gas Project, first gas from the deep water wells at the Liwan 3-1 gas field was achieved on March 30, 2014 with gas sales to the Guangdong market natural gas grid commencing on April 24, 2014. In addition, the tie-in of the Liuhua 34-2 field single production well into the Liwan 3-1 field deep water infrastructure was completed and commissioned with first gas production taking place in December 2014. Total conventional natural gas and natural gas liquids (“NGL”) production averaged approximately

114.2 mmcf/day and 4.2 mbbls/day, respectively.

 

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Progress continued on the shallow water gas developments in the Madura Strait Block during 2014. Work related to the BD field engineering, procurement, installation and construction contract continued. The contract for the construction and lease of a Floating Production, Storage and Offloading Vessel (“FPSO”) received final approval in the second quarter of 2014 and was signed in December 2014. The Plan of Development for the MDK field to tie into the MDA-MBH combined development was approved by SKK Migas in July 2014.

The Company signed a Production Sharing Contract (“PSC”) for the Anugerah contract area. Under the PSC, Husky has an obligation to carry out seismic surveys to assess the petroleum potential of the exploration block within the first three years.

2015

On February 23, 2015, the Company filed the Canadian Shelf Prospectus, which enables the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and other units in Canada up to and including March 23, 2017.

On March 6, 2015, the limit on the Company’s $1.6 billion revolving syndicated credit facility previously set to expire on December 14, 2016, was increased to $2.0 billion, and the limit on the $1.63 billion revolving syndicated credit facility set to expire on June 19, 2018 was increased to $2.0 billion. The terms of the revolving syndicated credit facilities remained unchanged.

On March 12, 2015, the Company repaid the maturing 3.75 percent medium-term notes issued under a trust indenture dated December 21, 2009. The amount paid to noteholders was $306 million, including $6 million of interest.

On March 12, 2015, the Company issued $750 million of 3.55 percent notes due March 12, 2025 by way of a prospectus supplement dated March 9, 2015 to the Canadian Shelf Prospectus. The notes are redeemable at the option of the Company at any time, subject to a make whole premium unless the notes are redeemed in the three month period prior to maturity. Interest is payable semi-annually on March 12 and September 12 of each year, beginning September 12, 2015. The notes are unsecured and unsubordinated and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness.

On March 12, 2015, the Company issued 8 million Series 5 Preferred Shares at a price of $25.00 per share for aggregate gross proceeds of $200 million, by way of a prospectus supplement dated March 5, 2015, to the Canadian Shelf Prospectus. Holders of the Series 5 Preferred Shares are entitled to receive a cumulative quarterly fixed dividend yielding 4.50 percent annually for the initial period ending March 31, 2020 as declared by the Board of Directors. See “Dividends - Dividend Policy and Restrictions - Series 5 Preferred Share Dividends”.

On June 17, 2015, the Company issued 6 million Series 7 Preferred Shares at a price of $25.00 per share for aggregate gross proceeds of $150 million, by way of a prospectus supplement dated June 10, 2015, to the Canadian Shelf Prospectus. Holders of the Series 7 Preferred Shares are entitled to receive a cumulative fixed dividend yielding 4.60 percent annually for the initial period ending June 30, 2020 as declared by the Board of Directors. See “Dividends - Dividend Policy and Restrictions - Series 7 Preferred Share Dividends”.

On December 22, 2015, the Company filed the U.S. Shelf Prospectus, which enables the Company to offer up to U.S. $3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the U.S. up to and including January 22, 2018.

A stock dividend was introduced in the third quarter as an interim measure in lieu of a cash dividend. Given the persistent downward pressure on oil prices and the extended lower for longer outlook, the Board of Directors subsequently suspended the quarterly dividend. No cash or share dividend was issued for the fourth quarter of 2015.

Construction continued at the two 10,000 bbls/day thermal developments Edam East and Vawn. Construction also continued at the 4,500 bbls/day Edam West heavy oil thermal development, where capacity increased from 3,500 bbls/day to 4,500 bbls/day in 2015 reflecting design and efficiency improvements.

Construction was completed at the Rush Lake thermal development with first oil achieved in July 2015. Production commenced ahead of schedule with production from the development reaching a year end exit rate of 13,900 bbls/day, exceeding its design capacity which was revised in 2015 from 10,000 bbls/day to 12,000 bbls/day.

The Company sanctioned Rush Lake 2, a 10,000 bbls/day heavy oil thermal development.

 

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The Sunrise Energy Project achieved first oil on Phase 1 in March 2015. Production from the Sunrise Energy Project continued to ramp-up.

Development activity at the White Rose core field and its satellites, including North Amethyst and the West and South White Rose Extensions, continued to advance. An exploration and appraisal drilling program continued at the Bay du Nord discovery in the Flemish Pass Basin in 2015, including ongoing drilling of the Bay d’Espoir exploration well.

The Company drilled and completed two production wells at the South White Rose Extension with peak production from the wells of 15,000 bbls/day (net Husky share) reached in early September. The Company secured the Henry Goodrich drilling rig for a two-year drilling program which will focus on development drilling at the White Rose field and satellite extensions.

Development continued at the Ansell liquids rich gas resource play, with 25 horizontal wells (gross) drilled and 28 horizontal wells (gross) completed.

At the Liwan Gas Project, the Company’s entitlement share of production from the Liwan Gas Project was reduced from approximately 76 percent in late May 2015 to its equity interest of 49 percent, reflecting the completion of exploration cost recoveries from the Liwan 3-1 field, which were originally funded solely by the Company.

The Company sanctioned the development of the MDA, MBH and MDK gas fields having secured the Gas Sales Agreement (“GSA”) for the first tranche of gas from the MDA-MBH fields development. The Company signed a PSC for an exploration block offshore China. The Company is the operator of the block during the exploration phase with a working interest of 100 percent. The Company also acquired 2-D and 3-D seismic survey data on the Anugerah contract area. Results from the seismic surveys’ data continue to be evaluated to determine the potential for future drilling opportunities.

The Company signed a PSC for the 15/33 contract area in the South China Sea. Under the PSC, Husky has an obligation to drill two exploration wells within the first three years.

The Company and Imperial Oil entered into a contractual agreement to create a single expanded truck transport network of approximately 160 sites.

At the Lima Refinery, the Company proceeded with the initial stages of a crude oil flexibility project designed to improve reliability at the facility and allow for the processing of up to 40,000 bbls/day of heavy crude oil feedstock from Western Canada. The crude oil flexibility project is designed to allow the Refinery to swing between light and heavy crude oil feedstock.

At the BP-Husky Toledo Refinery, a feedstock optimization project was sanctioned by the joint arrangement partners that was designed to improve the Refinery’s ability to process high content naphthenic acids (“High-TAN”) crude. The Refinery began processing bitumen from the Sunrise Energy Project in the second half of 2015.

2016

On March 9, 2016, the maturity date for one of the Company’s $2.0 billion revolving syndicated credit facilities, previously set to expire on December 14, 2016, was extended to March 9, 2020. In addition, the Company’s leverage covenant was modified to a debt to capital covenant.

In March 2016, holders of 1,564,068 Series 1 Preferred Shares exercised their option to convert their shares, on a one-for-one basis, to Series 2 Preferred Shares and receive a floating rate quarterly dividend.

On November 15, 2016, the Company repaid its maturing 7.55 percent notes issued under a trust indenture dated October 31, 1996. The amount paid to noteholders was $280 million, including $10 million of interest.

First oil was achieved at the 10,000 bbls/day Edam East heavy oil thermal development on April 18, 2016. Production from the development averaged 14,900 bbls/day in December 2016, exceeding its design capacity.

First oil was achieved at the 10,000 bbls/day Vawn heavy oil thermal development on June 16, 2016. Production from the development averaged 11,400 bbls/day in December 2016, exceeding its design capacity.

 

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First oil was achieved at the 4,500 bbls/day Edam West heavy oil thermal development on August 29, 2016. Production from the development averaged 4,200 bbls/day in December 2016.

First oil was achieved from the Colony formation, at the Tucker Thermal Project in the Cold Lake region of Alberta, on April 19, 2016. Total production from the Tucker Thermal Project averaged 21,700 bbls/day in December 2016.

Production from the Sunrise Energy Project was temporarily impacted by wildfires in the Fort McMurray region of Alberta in the second quarter of 2016. Operations were successfully restarted in the same quarter with all 55 well pairs back online and the plant being fully operational. Production from the Sunrise Energy Project is expected to continue to ramp up with average annual production in 2017 expected to be in the range of 40,000 to 44,000 bbls/day (20,000 to 22,000 bbls/day net Husky share).

The Henry Goodrich rig resumed operations at North Amethyst. First production was achieved from the North Amethyst Hibernia formation well on September 15, 2016. An additional well was brought into production at the South White Rose drill center on November 29, 2016. The rig has since drilled an infill well at North Amethyst.

Engineering design and subsurface evaluation work continues at West White Rose to increase capital efficiency and improve resource capture.

The exploration and appraisal drilling program at the Bay du Nord discovery in the Flemish Pass Basin was completed during 2016. Since the program commenced in the fourth quarter of 2014, the Company has participated in three appraisal and four exploration wells in and around Bay du Nord, leading to two new oil discoveries at Bay de Verde and Baccalieu and two unsuccessful wells at Bay d`Espoir and Bay du Loup. The Company holds a 35 percent non-operated working interest in each of the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. The Company and its partner continue to assess the commercial potential of these discoveries.

In November 2016, the Canada-Newfoundland and Labrador Petroleum Board announced that the Company was the successful bidder on two parcels of land in its 2016 land sale. The lands cover an area of 211,574 hectares and brought the Company’s exploration licences (“ELs”) in the region to eight. The southwest parcel is adjacent to the White Rose field and satellite extensions, while the other is northeast of the field and adjacent to other Husky operated ELs in the Jeanne d’Arc Basin.

Production continued at the Ansell liquids rich gas resource play, with production averaging 34,500 boe/day. Limited development activity was undertaken in 2016.

On May 25, 2016, the Company completed the sale of Western Canada royalty interests to a third party for gross proceeds of $165 million, resulting in a pre-tax gain of $163 million and an after-tax gain of $119 million.

During 2016, the company completed the sale of approximately 30,200 boe/day of legacy crude oil and gas assets in Western Canada for gross proceeds of $1.12 billion.

At the Liwan Gas Project, the second 22-inch subsea pipeline connecting the deepwater pipeline to the central platform was completed, tested and placed in service. This pipeline provides operating flexibility for the deepwater infrastructure and completes the Liwan facilities to its full design specification.

During the third quarter of 2016, the Company’s China subsidiary signed a Heads of Agreement (“HOA”) with China National Offshore Oil Corporation (“CNOOC”) and relevant companies for the price adjustment of natural gas from the Liwan 3-1 and Liuhua 34-2 fields with the revised price set at Cdn. $12.50 - Cdn. $15.00 per thousand cubic feet (mcf) at current exchange rates. Gross take-or-pay volumes from the fields remain unchanged in the range of 300-330 million cubic feet per day (mmcf/day). Liquids production, net to Husky, is also expected to remain in the range of 5,000 - 6,000 bbls/day. The price adjustment under the HOA is effective as of November 20, 2015, and the settlement of outstanding payment was calculated from that date.

At the Madura Strait, the shallow water gas developments continued to progress. At the liquids-rich BD field, development well drilling, completion and testing of all four wells has been completed. The facilities construction project is approximately 97 percent complete including the installation and testing of the shallow water platform, the subsea pipeline to shore and the onshore gas metering station. The FPSO vessel construction has been completed and the vessel is now moored at the field location in preparation for in-situ testing and commissioning. The project is on target for first production in the 2017 timeframe and is scheduled to ramp up to its full gas sales rate by the second half of 2017.

 

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The Company has secured a gas sales agreement for the MDA and MBH fields, which will be developed in tandem. Negotiations of additional gas sales agreements for the MDA, MBH and MDK gas fields are in progress. A re-tendering process for a floating production vessel has been completed and the winning bidder was approved by SKK Migas. The vessel lease contract is being finalized and is planned to be signed in early 2017. Tendering is also underway for related engineering, procurement, construction and installation contracts. Production from the MDA, MBH and MDK fields is expected in the 2018 - 2019 timeframe.

On July 15, 2016, the Company completed the sale of 65 percent of its ownership interest in select midstream assets in the Lloydminster region of Alberta and Saskatchewan for gross proceeds of $1.69 billion in cash. The assets include approximately 1,900 kilometres of pipeline in the Lloydminster region, 4.1 mmbbls of storage capacity at Hardisty and Lloydminster and other ancillary assets. The assets are held by a newly formed limited partnership, Husky Midstream Limited Partnership (“HMLP”), of which Husky owns 35 percent, Power Assets Holdings Limited (“PAH”) owns 48.75 percent and Cheung Kong Infrastructure Holdings Limited (“CKI”) owns 16.25 percent. The transaction enabled the Company to further strengthen its balance sheet while maintaining operatorship and preserving the integration between its heavy oil production, marketing and refining assets. Proceeds from the transaction were received in the third quarter of 2016.

The Company and Imperial Oil received regulatory approval from the Canadian Competition Bureau during the second quarter of 2016 to create a single expanded truck transport network. The contract closing conditions were met late in the fourth quarter 2016 and the consolidation of the two networks is expected in the second half of 2017. This agreement will create an expanded fuel network across Canada to better serve Husky’s commercial trucking customers while Imperial will be providing fuel and marketing support. Under the agreement, Imperial Oil will convert its commercial sites to a branded wholesaler model. Husky will convert its commercial cardlocks, co-located Travel Centres and a select number of retail service stations to the Esso brand. Husky will assume management of all dealer relationships in the combined network, as well as ongoing network growth as an Esso-branded wholesaler. The expanded network will have 160 sites, effectively doubling the size of Husky’s existing cardlock network.

The Company has started pre front-end engineering and design (“FEED”) work on a potential 30,000 bbls/day expansion of its asphalt processing capacity in Lloydminster. This business continues to show strong returns through the cycle, and its expansion would provide an additional outlet for the Company’s growing heavy oil thermal production.

At the Lima Refinery, the Company continued to work on a crude oil flexibility project designed to improve reliability at the facility and allow for the processing of up to 40,000 bbls/day of heavy crude oil feedstock from Western Canada. The full scope of the project is expected to be completed in 2018.

The Company and its partner completed a feedstock optimization project at the BP-Husky Toledo Refinery in mid-July 2016. The Refinery is now able to process approximately 65,000 bbls/day of High-TAN crude oil to support production from the Sunrise Energy Project. The Refinery’s overall nameplate capacity remains unchanged at 160,000 bbls/day.

 

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DESCRIPTION OF HUSKY’S BUSINESS

General

Husky is a publicly traded international integrated energy company headquartered in Calgary, Alberta, Canada.

Management has identified segments for the Company’s business based on differences in products, services and management responsibility. The Company’s business is conducted predominantly through two major business segments - Upstream and Downstream.

Upstream includes exploration for, and development and production of, crude oil, bitumen, natural gas and NGLs (Exploration and Production) and marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke, pipeline transportation, the blending of crude oil and natural gas and storage of crude oil, diluent and natural gas (Infrastructure and Marketing). Infrastructure and Marketing markets and distributes products to customers on behalf of Exploration and Production and is grouped in the Upstream business segment based on the nature of its interconnected operations. The Company’s Upstream operations are located primarily in Western Canada, offshore East Coast of Canada (Atlantic Region) and offshore China and offshore Indonesia (Asia Pacific Region).

Downstream includes upgrading of heavy crude oil feedstock into synthetic crude oil in Canada (Upgrading), refining in Canada of crude oil, marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol (Canadian Refined Products) and refining in the U.S. of primarily crude oil to produce and market gasoline, jet fuel and diesel fuels that meet U.S. clean fuels standards (U.S. Refining and Marketing). Upgrading, Canadian Refined Products and U.S. Refining and Marketing all process and refine natural resources into marketable products and therefore are grouped together as the Downstream business segment due to the similar nature of their products and services.

Social and Environmental Policy

Husky has a Health, Safety and Environment Policy that affirms its commitment to operational integrity. Operational integrity at Husky means conducting all activities safely and reliably so that the public is protected, impact to the environment is minimized, the health and wellbeing of employees are safeguarded, contractors and customers are safe and physical assets (such as facilities and equipment) are protected from damage or loss.

The Health, Safety and Environment Committee of the Board of Directors (the “HS&E Committee”) is responsible for oversight of health, safety and environment policy, oversight of audit results and monitoring compliance with the Company’s environmental policies, key performance indicators and regulatory requirements. The mandate of the HS&E Committee is available in the Governance section of the Husky website at www.huskyenergy.com.

To reinforce the Health, Safety and Environment Policy, Husky holds an annual summit for leaders, attended by members of the HS&E Committee and led by the Chief Executive Officer. During the Summit, CEO awards are presented to the submissions that demonstrate the highest level of operational integrity. Guest and internal speakers present on pertinent issues and the latest developments in the field of operational integrity and corporate responsibility.

Husky is committed to upholding high standards of business integrity and seeks to deter wrongdoing and to promote transparent, honest and ethical behaviour in all of its business dealings. The Company has a Code of Business Conduct policy that sets out the standards employees, contractors, officers and directors are expected to meet. The policy includes sections on compliance with laws, avoidance of conflict of interest, proper record-keeping, political contributions, safeguarding of company resources, fair competition, avoidance of bribery or other offering of improper payments, guidelines on accepting payments and entertainment and other matters. The policy is available on the Husky website at www.huskyenergy.com.

Husky has established an anonymous and confidential online reporting tool and toll-free telephone numbers for employees, contractors and other stakeholders to report perceived breaches of the Company’s Code of Business Conduct. The Ethics Help Line is hosted by EthicsPoint, an independent service provider. Information from submissions are captured and submitted anonymously to an Ethics Help Line Committee, made up of legal, audit, security, health safety and environment and human resources personnel.

 

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Husky is committed to conducting business fairly, with integrity and in compliance with all applicable laws, and has an Anti-Bribery & Anti-Corruption Policy to reinforce the Code of Business Conduct with additional guidance regarding applicable anti-bribery and anti-corruption laws. All officers and employees, including temporary and contract staff, are expected to observe the highest standards of honesty, integrity, diligence and fairness in all business activities.

Husky is an equal opportunity employer committed to an environment that is free of harassment and violence and where respectful treatment is the norm. The Husky Diversity and Respectful Workplace Policy applies to all employees and contractors.

As a responsible and constructive member of the communities in which it operates, Husky has a Community Investment Program that supports charitable organizations in many communities. The Community Investment Policy provides guidance with the general goal of ensuring that contributions under the Community Investment Program are supported by a consistent and rigorous decision making process and reflect Husky’s core corporate values and business strategy.

Husky has an External Scholarships and Educational Support Policy that encourages the pursuit of advanced education by providing financial assistance to qualified students pursuing studies at a number of post-secondary educational institutions, reinforcing Husky’s commitment to support the communities where it conducts business. The policy includes Husky’s Aboriginal Education Awards Program which assists Aboriginal people in achieving greater career success by encouraging them to pursue an advanced education.

Husky values continued education and professional development and provides employees with opportunities for development and continuing advancement of their skills, knowledge and experience. The Learning and Development policy sets out guidelines, eligibility and support for Husky employees.

Husky is committed to the security and protection of personnel, physical assets, property and information from criminal, hostile or malicious acts, consistent with the Husky Security Policy. The Policy aims to reduce exposure to security risks with the general goal of ensuring the consistent application of security measures within Husky.

Husky is committed to ensuring health and safety at work. The ability of every employee or contractor to perform his/her particular job duties satisfactorily and safely is critical to Husky’s continued success. Husky recognizes that the use of illicit drugs and other mood altering substances, and the inappropriate use of alcohol and medications, can have serious adverse effects on job performance and ultimately on the safety and well-being of employees, contractors, customers, the public and the environment. In light of this, and the safety-sensitive nature of our operations, the Husky Alcohol and Drug Policy outlines the standards and expectations associated with alcohol and other drug use, consistent with Husky’s overall safety culture.

The above policies are available to employees and contractors on the Company’s intranet. Communication of the policies is provided through direct e-mail and through articles published on the Company’s intranet. Mandatory training is provided as relevant to the policy and the individual’s role via various mechanisms including in-class, web-based and self-serve.

Husky Operational Integrity Management System

Husky approaches social responsibility and sustainable development by seeking a balance among economic, environmental and social factors while maintaining growth. Husky strives to find solutions to issues that do not compromise the needs of future generations. In 2008, Husky implemented the Husky Operational Integrity Management System (“HOIMS”), which is followed by all Husky businesses. HOIMS is a systematic approach to anticipating, identifying and mitigating hazardous situations within the Company’s operations. The implementation of HOIMS has produced tangible business results, including improved performance, fewer incidents and enhanced business value. It incorporates best practices from across the industry, consistent with Husky’s commitment to excellence in operational integrity. HOIMS includes 14 fundamental elements; each element contains well defined objectives and expectations that guide Husky to continuously improve operational integrity. Resources are dedicated to the continued implementation and execution of HOIMS, and audits are conducted with the general goal of ensuring that HOIMS is effectively integrated into daily operations.

 

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The fundamental elements of HOIMS are:

 

  1. Ensure all levels of management demonstrate leadership and commitment to operational integrity. Define and ensure appropriate accountability for HOIMS throughout the organization.

 

  2. Prevent incidents by identifying and minimizing workplace and personal health risks. Promote and reinforce all safe behaviours.

 

  3. Manage risks by performing comprehensive risk assessments to provide essential decision-making information. Develop and implement plans to manage significant risks and impacts to as low as reasonably practical levels.

 

  4. Be prepared for an emergency or security threat. Identify all necessary actions to be taken to protect people, the environment, the organization’s assets and reputation in the event of an emergency or security threat.

 

  5. Maintain operations reliability and integrity by use of clearly defined and documented operational, maintenance, inspection and corrosion programs. Seek improvements in process and equipment dependability by systematically eliminating defects and sources of loss.

 

  6. Provide assurance that personnel possess the necessary competencies, knowledge, abilities and behaviours to perform and demonstrate designated tasks and responsibilities effectively, efficiently and safely.

 

  7. Report and investigate all incidents. Learn from incidents and use the information to take corrective action and prevent recurrence.

 

  8. Operate responsibly to minimize the environmental impact of operations. Leave a positive legacy behind when operations cease.

 

  9. Ensure that risks and exposures from proposed changes are identified, evaluated and managed to remain at an acceptable level.

 

  10. Identify, maintain and safeguard important information. Ensure personnel can readily access and retrieve information. Promote and encourage constructive dialogue within the organization to share industry recommended practices and acquired knowledge.

 

  11. Ensure conformance with corporate policies and compliance with all relevant government regulations. Work constructively to influence proposed laws and regulations, and debate on emerging issues.

 

  12. Design, construct, commission, operate and decommission all assets in a healthy, safe, secure, environmentally sound, reliable and efficient manner.

 

  13. Ensure contractors and suppliers perform in a manner that is consistent and compatible with Husky’s policies and business performance standards. Ensure contracted services and procured materials meet the requirements and expectations of Husky’s standards.

 

  14. Confirm that HOIMS processes are implemented and assess whether they are working effectively. Measure progress and continually improve towards meeting HOIMS objectives, targets, and key performance indicators.

Environmental Protection

Husky’s operations are subject to various environmental requirements under federal, provincial, state and local laws and regulations, as well as international conventions. These laws and regulations cover matters such as air emissions, wastewater discharge, non-saline water use, protection of surface water and groundwater, land disturbances and handling and disposal of waste materials. These regulatory requirements have grown in number and complexity over time, covering a broader scope of industry operations and products. In addition to existing requirements, Husky recognizes that there are emerging regulatory frameworks that may have a financial impact on the Company’s operations. See “Risk Factors” and “Industry Overview”.

Directly and through joint venture partnerships, Husky is a member of several industry associations that collaborate to identify and implement best practices on environmental performance. International Petroleum Industry Environmental Conservation Association (“IPIECA”) produces guidelines that Husky uses to improve its environmental practices, enhance its strategic planning, engage with regulators and enhance operations. Husky is also a member of the International Emissions Trading Association (“IETA”) whose objective is to build international policy and market frameworks for reducing greenhouse gases (“GHG”) at lowest cost. As a member of the Petroleum Technology Alliance Canada, Husky participates in technology research for energy efficiency and emissions reduction.

 

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In addition, as an active member of the In-situ Water Technology Development Centre, Husky is developing new technologies to reduce energy and water use. Husky dedicates teams to water management issues, with expertise in hydrogeology, surface water aquatics, hydrology, water treatment and drilling waste management. Husky continues to seek ways to conserve and recycle water, including looking at alternative water sources and recycling produced water. At the Tucker Thermal Facility, produced water is recycled and make up water is sourced from saline, non-potable groundwater. The Sunrise Energy Project recycles produced water and supplements this with process-affected water from a nearby oil sands operation (after it has been treated) and non-saline groundwater to generate steam for oil recovery.

Ongoing remediation and reclamation work is occurring at approximately 3,500 well sites and facilities. In 2016, Husky spent approximately $87 million on Asset Retirement Obligations (“ARO”), and the Company expects to spend approximately $123 million in 2017 on environmental site closure activities, including abandonment, decommissioning, reclamation and remediation in North America. In the Asia Pacific Region, in accordance with the provisions of the regulations of the People’s Republic of China, Husky has deposited funds into separate accounts restricted to the funding of future asset retirement obligations. As at December 31, 2016, Husky has deposited funds of $156 million into the restricted cash accounts, of which $84 million relates to the Wenchang field and has been classified as current.

The Company completed a review of its ARO provisions, including estimated costs and projected timing of performing the abandonment and retirement operations. The results of this review have been incorporated into the estimated liability as disclosed in Note 16 of the Company’s 2016 audited consolidated financial statements.

Husky has an ongoing environmental monitoring program at owned and leased retail locations and performs remediation where required. Husky also has ongoing monitoring programs at its Downstream facilities, including refineries and the Lloydminster Upgrader.

Husky has several “legacy” (inactive facility) sites ranging from former refineries to retail locations. Management and remediation plans are prepared for these sites based on current and future land use.

As part of the Company’s review of proposed regulations that may affect its business and operations, the Company may, from time to time, prepare an internal analysis of the possible or expected impact of new regulations, which are subject to various uncertainties. It is not possible to predict with certainty the amount of additional investment in new or existing facilities required to be incurred in the future for environmental protection or to address regulatory compliance requirements, such as reporting. Costs associated with levy payments for emerging climate change regulations may be significant. See “Risk Factors - Climate Change Regulation” for a description of the impact that climate change regulations may have on the Company.

 

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Upstream Operations

Description of Major Properties and Facilities

Husky’s portfolio of Upstream assets includes properties with reserves of light crude oil, medium crude oil, heavy crude oil, bitumen, NGL, natural gas and sulphur.

China

 

LOGO

Liwan Gas Project

The Liwan Gas Project includes the natural gas discoveries at the Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 fields within the Contract Area 29/26 exploration block located in the Pearl River Mouth Basin of the South China Sea, approximately 300 kilometres southeast of the Hong Kong Special Administrative Region.

The Company has a 49 percent working interest in the project and CNOOC has a 51 percent interest. The project was separated into deep water and shallow water development projects, with the Company acting as deep water operator and CNOOC acting as shallow water operator. The deep water infrastructure includes production wells and trees, subsea pipelines and manifolds that produce to twin 22-inch deepwater pipelines running approximately 78 kilometres to a shallow water central platform. The shallow water infrastructure includes the central platform standing in approximately 120 metres of water, a 261 kilometre shallow water pipeline running from the central platform to the onshore Gaolan Gas Plant and the onshore gas plant with liquids separation facilities, ten spherical NGL storage tanks, an export jetty, control facilities as well as administrative and accommodation buildings.

The Liwan 3-1 field commenced production at the end of March 2014. The gas field is currently producing from nine wells to the central platform and on through to the onshore Gaolan Gas Plant. The single production well in the Liuhua 34-2 field was tied into the deep water facilities of the Liwan 3-1 field and commenced production in December 2014.

 

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Gas sales from Liwan 3-1 and Liuhua 34-2 averaged 189 mmcf/day and 35 mmcf/day (gross), respectively, in 2016. In 2016, the Company’s share of production from the two fields was 113 mmcf/day of conventional natural gas and 5.9 mbbls/day of NGL. Negotiations for the sale of the gas from the Liuhua 29-1 field are being pursued. Also in 2016, the Company completed the construction and tie-in of a second deepwater production pipeline to the shallow water central platform that will provide redundancy and production capacity for the future.

Wenchang

The Wenchang field is located in the western Pearl River Mouth Basin, approximately 400 kilometres south of the Hong Kong Special Administrative Region and 100 kilometres east of Hainan Island. The Company holds a 40 percent working interest in two oil fields, which commenced production in July 2002. The Wenchang 13-1 and 13-2 oil fields are currently producing from 32 wells in 100 metres of water into an FPSO stationed between fixed platforms located in each of the two fields. The Company’s share of production averaged 6.6 mbbls/day and 0.2 mbbls/day of light crude oil and NGL, respectively, during 2016. In 2016, the PSC was extended for 130 days corresponding to the duration of production suspension for FPSO maintenance experienced in 2014. The PSC is now due to expire in November 2017, after which the Company will no longer have a working interest in this field.

Block 15/33

The Company executed a PSC in December 2015 for an exploration block offshore China. The 15/33 block is located in the Pearl River Mouth Basin in the South China Sea, about 140 kilometres southeast of the Hong Kong Special Administrative Region and covers an area of 155 square kilometres in water depths of approximately 80 - 100 metres. The Company is the operator of the block during the exploration phase, with a working interest of 100 percent. In the event of a commercial discovery, its partner CNOOC may assume a working interest of up to 51 percent during the development and production phase. Under the PSC, the corresponding CNOOC share of exploration cost recovery from production is to be allocated to the Company. The Company expects to drill two exploration wells in the 2017/2018 timeframe.

Taiwan

In December 2012, the Company signed a joint venture agreement with CPC Corporation. The Company and CPC Corporation have rights to an exploration block in the South China Sea covering approximately 7,700 square kilometres located southwest of the island of Taiwan. The Company holds a 75 percent working interest during exploration, while CPC Corporation has the right to participate in the development program up to a 50 percent interest.

Analysis of the 2-D seismic survey data acquired in 2014 has been completed and a number of significant prospects have been identified. The Company plans to acquire 3-D seismic survey data on the most attractive prospects during 2017.

Indonesia

 

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Madura Strait

The Company has a 40 percent interest in approximately 622,000 acres (2,516 square kilometres) of the Madura Strait Block, located offshore East Java, south of Madura Island, Indonesia. The Company’s two partners are CNOOC, which is the operator and has a 40 percent working interest, and Samudra Energy Ltd., which holds the remaining 20 percent interest through its affiliate, SMS Development Ltd.

In October 2010, the Government of Indonesia approved an extension of the PSC that was originally awarded in 1982. The approval provided a 20-year extension to the contract, which now runs until 2032. The BD field Front End Engineering Design (“FEED”) was completed in the second quarter of 2010.

In 2011, CNOOC drilled an appraisal well that confirmed commercial quantities of hydrocarbons in the MDA field. An exploration well was also drilled in 2011 on the MBH field, and a new gas field was discovered. The gas sales contracts for the BD field previously signed in 2010 with three gas buyers were amended in 2011. In November 2012, the functions of BP Migas, the Indonesian oil and gas regulator at the time, were temporarily transferred to the Energy and Mineral Resources Ministry and subsequently, a new body, SKK Migas, was established as the new industry regulator. As discussed and agreed with the new regulator, a re-tender for the BD field FPSO was made.

In 2012, the exploration drilling program resulted in discoveries on the MAC, MAX, MDK and MBJ fields.

In January 2013, the Plan of Development for a combined MDA and MBH development project was approved by SKK Migas. In July 2013, the BD field engineering, procurement, installation and commissioning contract was awarded and engineering/construction work under the contract commenced. The Government of Indonesia appointed a lead distributor for the major portion of the gas from the MDA and MBH fields and a HOA was signed. Exploration drilling on the block in 2013 resulted in an additional discovery at the MBF field.

In 2014, the tender plans for the combined development project for the MDA-MBH fields were approved by SKK Migas. The Plan of Development for the MDK field to tie into the MDA-MBH combined development was approved by SKK Migas in July 2014. A contract for the lease of an FPSO for the BD field was signed in December 2014.

In 2015, engineering and construction work continued at the liquids-rich BD field where the platform jacket and topsides were successfully set in approximately 55 metres of water in October 2015 and development drilling commenced in November 2015.

In November 2015, the Company sanctioned the development of the MDA, MBH and MDK gas fields and the GSA for the first tranche of gas from the MDA-MBH development was signed. In December 2015, the Minister of Energy and Mineral Resources appointed the buyers for the remaining available tranches of gas sales from the three fields and negotiation of the GSAs commenced in 2016. Also in November 2015, SKK Migas approved the plan of development for the MAC gas field which was discovered in 2012.

Progress continued on the shallow water gas developments during 2016. At the liquids-rich BD field, development well drilling, completion and testing of all four wells was completed. The facilities construction project is approximately 97 percent complete including the installation and testing of the shallow water platform, the subsea pipeline to shore and the onshore gas metering station. The FPSO vessel construction was completed and the vessel is now moored at the field location in preparation for in-situ testing and commissioning. The project is on target for first production in the 2017 timeframe and is scheduled to ramp up to its full gas sales rate by the second half of 2017.

The Company has secured a GSA for the MDA and MBH fields, which are expected to be developed in tandem. Negotiations of additional GSAs for the MDA, MBH and MDK gas fields are in progress. A re-tendering process for a floating production vessel has been completed and the winning bidder was approved by SKK Migas. The lease contract for the vessel is being finalized and is expected to be signed in early 2017. Tendering is also underway for related engineering, procurement, construction and installation contracts. Production from the MDA, MBH and MDK fields is expected in the 2018—2019 timeframe. Combined net sales volumes from the BD, MDA, MBH and MDK fields are expected to be approximately 100 mmcf/day of natural gas and 2,400 bbls/day of associated NGLs once production is fully ramped up.

 

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Anugerah

The Company executed a PSC in February 2014 with the Government of Indonesia for the Anugerah contract area. The Company holds a 100 percent interest in the Anugerah Block, which is located in the East Java Basin approximately 150 kilometres east of the Madura Strait Block. The block covers an area of 2,030,000 acres (8,215 square kilometres) with potential drilling opportunities in water depths of 800 to 1,300 metres. The PSC requires the acquisition of 2-D and 3-D seismic data during the first three years of the contract. In 2015 and 2016, a seismic acquisition program was carried out, and results are being evaluated to determine potential for future drilling opportunities.

Atlantic Region

The Company’s offshore East Coast exploration and development program is focused in the Jeanne d’Arc Basin on the Grand Banks, which contains the Hibernia and Terra Nova fields, the White Rose field and satellite extensions, including North Amethyst, West White Rose and South White Rose, and the Flemish Pass Basin. In the Flemish Pass, the Company holds a 35 percent non-operated working interest in each of the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. The Company is the operator of the White Rose field and satellite extensions and holds an ownership interest in the Terra Nova field, as well as a number of smaller undeveloped fields. The Company also holds significant exploration acreage offshore Newfoundland.

White Rose Oil Field

The White Rose oil field is located 354 kilometres off the coast of Newfoundland and Labrador and approximately 48 kilometres east of the Hibernia oil field on the eastern flank of the Jeanne d’Arc Basin. The Company is the operator of the main White Rose field and satellite tiebacks, including the North Amethyst, West White Rose and South White Rose extensions. The Company has a 72.5 percent working interest in the main field and a 68.875 percent working interest in the satellite extensions.

First oil was achieved at White Rose in November 2005. The White Rose field was the third oil field developed offshore Newfoundland and currently has 10 production wells, 10 water injection wells and three gas storage wells. During 2016, the Company’s light crude oil production from the White Rose field was 16.9 mbbls/day (net Husky share).

On May 31, 2010, first oil was achieved from North Amethyst, the first satellite extension to the White Rose field. The field is located approximately six kilometres southwest of the SeaRose FPSO. Production flows from North Amethyst to the SeaRose FPSO through a series of subsea flow lines. During 2016, the Company’s light crude oil production from North Amethyst was 4.9 mbbls/day (net Husky share). In September 2016, the Company began production from the deeper Hibernia formation at North Amethyst utilizing existing infrastructure. As of December 31, 2016, the field had six production wells and four water injection wells.

Initial production from West White Rose was achieved in September 2011 through a two-well pilot project. These wells have helped provide further information on the reservoir to refine development plans for the full West White Rose field. During 2016, the Company’s share of light crude oil production from this satellite field was 3.2 mbbls/day (net Husky share).

The Company continues to assess potential development options for the West White Rose satellite extension. One of the two concepts being assessed, a fixed wellhead platform, received government and regulatory approvals in 2015. A subsea option to develop the field is also being evaluated.

Production commenced from the South White Rose Extension in 2015 and development drilling continues. Production wells will be supported by both gas flood and water injection. The South White Rose Extension was developed in phases, with gas injection equipment installed in 2013 and oil production equipment installed in 2014. As at December 31, 2016, the project had two production wells and one gas injection well. During 2016, the Company’s share of light crude oil production from the South White Rose Extension was 3.8 mbbls/day (net Husky share).

Terra Nova Oil Field

The Terra Nova field is located approximately 350 kilometres southeast of St. John’s, Newfoundland. The Terra Nova field is divided into three distinct areas, known as the Graben, the East Flank and the Far East. Production at Terra Nova commenced in January 2002. The Company’s working interest in the field increased to 13 percent effective December 1, 2010.

 

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As at December 31, 2016, there were 14 development wells drilled in the Graben area, consisting of eight production wells, three water injection wells and three gas injection wells. In the East Flank area, there were 14 development wells, consisting of eight production wells and six water injection wells. The Far East has one extended reach producer and an extended reach water injection well. The operator continues to progress delineation and development opportunities at Terra Nova.

Light crude oil production during 2016 from the Terra Nova field was 4.3 mbbls/day (net Husky share).

East Coast Exploration

The Company presently holds working interests ranging from 5.8 percent to 73.125 percent in 23 significant discovery areas in the Jeanne d’Arc Basin and Flemish Pass Basin, offshore Newfoundland and Labrador and Baffin Island.

In June 2016, the Company and its partner announced two oil discoveries at the Bay de Verde and Baccalieu prospects in the Flemish Pass Basin, which add to the resource base for a potential development at the Bay du Nord discovery. The wells were drilled as part of an 18 month long appraisal drilling program in which the Company participated in three appraisal and four exploration wells. The Company holds a 35 percent non-operated working interest in each of the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. The Company and its partner continue to assess the commercial potential of these discoveries.

In November 2016, the Canada-Newfoundland and Labrador Petroleum Board announced that the Company was the successful bidder on two parcels of land in its 2016 land sale. The lands cover an area of 211,574 hectares and brought the Company’s ELs in the region to eight. The southwest parcel is adjacent to the White Rose field and satellite extensions, while the other is northeast of the field and adjacent to other Company operated ELs in the Jeanne d’Arc Basin.

 

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LOGO

Greenland

The Company has decided not to elect to enter sub-Period 2 for either of its two ELs offshore West Greenland, and consequently, these licences expired in 2016.

 

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Heavy Oil

The majority of the Company’s heavy oil assets are located in the Lloydminster region of Alberta and Saskatchewan, with lands consisting of approximately two million acres. This extensive land position spans most of the productive oil fields in the area, all within 100 kilometres of the City of Lloydminster. The Company operates over 4,500 wells in the area, with a 100 percent working interest in the majority of these wells. The Company’s operations are supported by a network of Company owned treating facilities and operated pipelines that transport heavy crude oil from the field locations to the Husky Lloydminster Asphalt Refinery, the Husky Lloydminster Upgrader and third-party pipeline systems at Hardisty, Alberta, providing full integration with the Company’s Upstream Infrastructure and Marketing and Downstream businesses.

Production of heavy crude oil and bitumen from the Lloydminster area uses a variety of technologies including Steam Assisted Gravity Drainage (“SAGD”) or Thermal production, Cold Heavy Oil Production with Sand (“CHOPS”), Horizontal Wells, Waterflooded fields and Non-Thermal Enhanced Oil Recovery (“EOR”). The Company is pursuing a significant expansion of its Heavy Oil Thermal production while actively managing the natural decline in its CHOPS production. The Company also produces natural gas from numerous small shallow pools in the Lloydminster region and recovers solution gas produced from heavy crude oil wells.

Lloydminster Thermal Developments

Lloydminster Thermal production consists of nine Thermal plants located in the Lloydminster region of Saskatchewan: Bolney, Edam East, Edam West, Paradise Hill, Pikes Peak, Pikes Peak South, Rush Lake, Sandall, and Vawn. Each plant has numerous production pads and utilizes SAGD technology.

During 2016, construction was completed at the Edam East, Vawn and Edam West heavy oil thermal developments; heavy crude oil production averaged 14,900 bbls/day, 11,400 bbls/day and 4,200 bbls/day, respectively, in December 2016.

In 2016, the Company sanctioned three new Lloyd thermal projects with total design capacity of about 30,000 bbls/day at Dee Valley, Spruce Lake North and Spruce Lake Central. Subject to regulatory approval, first production for all three thermal projects is expected in 2020.

In 2017, work will continue on the 10,000 bbls/day Rush Lake 2 thermal development, with first oil expected in the first half of 2019.

Tucker Lake Oil Sands Thermal Development

Tucker Lake is an in-situ SAGD oil sands project located 30 kilometres northwest of Cold Lake, Alberta that commenced Bitumen production at the end of 2006.

In December 2016, Tucker Lake Thermal Project bitumen production averaged 21,700 bbls/day, with production estimated to reach 30,000 bbls/day by 2019 with further development and optimization.

Non-Thermal Oil Production

The Company operates approximately 3,500 CHOPS heavy oil vertical wells, 550 horizontal heavy oil wells and 300 waterflooded medium crude oil wells located in the Lloydminster areas in Alberta and Saskatchewan.

Non-Thermal Enhanced Oil Recovery

The Company operated five carbon dioxide (“CO2”) injection EOR pilot projects in 2016 and a CO2 capture and liquefaction plant at the Lloydminster Ethanol Plant. The liquefied CO2 is used in the ongoing EOR piloting program.

McMullen Willow Creek Thermal Development

The Company will commence oil sands evaluation drilling of 19 wells at McMullen Willow Creek in the first quarter of 2017 and progress towards an Alberta Energy Regulator (“AER”) application in the second quarter of 2017. First oil for the 10,000 bbls/day Phase I Plant based on the development plan is 2024 with a conceptual plan to progress up to nine additional plants by 2040.

 

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Oil Sands

Sunrise Energy Project

On March 31, 2008, Husky and BP completed a transaction that created an integrated North American oil sands business. The business is comprised of a 50/50 partnership to develop the Sunrise Energy Project, operated by Husky, and a 50/50 limited liability company for the BP-Husky Toledo Refinery, operated by BP.

The Sunrise Energy Project is an in-situ SAGD oil sands project located in the Athabasca region of northern Alberta. The project will be developed in multiple phases with Phase 1 consisting of two 30,000 bbls/day of bitumen plants (Plants 1A and 1B). The project was sanctioned in 2010 after which the Company awarded major engineering and construction contracts for the central processing and field facilities. During 2010, the partnership reached an agreement on the movement of diluted bitumen to market and transportation of diluent to the Sunrise oil sands site. Development drilling of all planned SAGD horizontal well pairs for Phase 1 were completed in 2012. Construction of the Central Processing Facilities and field facilities were substantially completed in 2014. Steaming from Plant 1A commenced in late 2014, and first oil was achieved in the first quarter of 2015. At the end of December 2016, there were 55 producing well pairs. In 2016, bitumen production averaged approximately 25,600 bbls/day (12,800 bbls/day net Husky share). The production ramp-up will continue through the coming year and production is expected to increase to an annual average of approximately 40,000 - 44,000 bbls/day (20,000 - 22,000 bbls/day net Husky share) in 2017.

Western Canada (excluding Heavy Oil and Oil Sands)

Foothills Operations

Foothills operations are located primarily in Western Alberta. Primary areas of operations consist of Rocky Mountain House, Edson and Grande Prairie. This newly formed operations area is centered on a gas resource growth strategy.

Within Foothills operations, the Company operates 300 facilities, including the Ram River Gas Plant in which the Company has an average 85 percent working interest. Production in 2016 consisted of approximately 2.1 mbbls/day of light and medium crude oil, 6.4 mbbls/day of NGL and 270.2 mmcf/day of natural gas.

The area is heavily weighted towards natural gas production at approximately 81 percent. The Company is pursuing liquids-rich natural gas development opportunities within the existing asset portfolio primarily in the Ansell and Kakwa area. The Kakwa Wilrich liquids rich gas resource play south of Grande Prairie is a non-operated asset in which the Company has a 50 percent working interest. During 2016, production averaged 3.2 mboe/d, respectively (net Husky share) with one new horizontal well (gross) drilled.

Resource oil development is focused on the Cardium oil play in the Wapiti area south of the city of Grand Prairie, Alberta, utilizing horizontal well and multi-stage fracturing technology to unlock crude oil reserves in the Cardium zone. During 2016, production for the play averaged 1.7 mboe/day. No development was carried out in 2016.

Edson operations are located primarily in Northern Alberta and consist of the Ansell and Galloway areas. The Ansell liquids-rich natural gas resource play is located in the deep basin Cretaceous formations of West-Central Alberta with the Company holding an average 92 percent working interest in approximately 150 net sections of contiguous lands. The Company has been actively developing the Spirit River Wilrich and Notikewin formations using multi-stage fractured horizontal wells since 2012. Production from the Ansell/Galloway area has doubled since 2012 and in 2016 averaged 2.2 mbbls/day of NGL and 107.4 mmcf/day of conventional natural gas. The Company operates over 370 producing wells (gross) at Ansell including 40 Spirit River horizontal wells (gross) and 20 Cardium horizontal wells (gross).

The Company’s activity in this area decreased in 2016 due to low natural gas prices. The Company drilled two horizontal wells (gross) and completed four horizontal wells (gross) during 2016. At year end, one rig was drilling in the area with a second scheduled to start up in early 2017.

Plans in 2017 for Foothills include a 16 well development program targeting the Spirit River formation.

 

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Plains Operations

The Company’s Western Canada Plains operations are located in Central Alberta, Northern Alberta and Southwest Saskatchewan. As at December 31, 2016, the Company operates 30 crude oil and 20 natural gas facilities with approximately 4,000 active wells throughout the area. Production in 2016 from these operations averaged 21.9 mbbls/day of crude oil, 0.9 mbbls/day of NGL and 83.8 mmcf/day of natural gas.

Rainbow Lake Development

Rainbow Lake, located approximately 900 kilometres northwest of Edmonton, Alberta, is the site of the Company’s largest light oil production operation in Western Canada. Production during 2016 from the Rainbow Lake Development averaged 6.6 mbbls/day of light crude oil, 0.7 mbbls/day of NGL and 70.7 mmcf/day of natural gas.

In 2016, the Company progressed modifications to its Rainbow Lake processing plant that are expected to enable sales of 4.0 mbbls/day of NGL by the second quarter of 2017.

The Company holds a 50 percent interest in a 90 megawatt natural gas fired cogeneration facility adjacent to its Rainbow Lake processing plant. The cogeneration facility produces electricity and thermal energy, or steam, for the Rainbow Lake processing plant. Additional electricity is also generated for the Power Pool of Alberta.

Northwest Territories

The Company holds two ELs acquired in 2011 in the Northwest Territories at the Slater River Canol shale play. These were consolidated as one EL in 2015 and cover 483,000 gross acres (466,000 net acres) in the Northwest Territories. Two vertical pilot wells were drilled, completed and flow tested in 2012. These wells satisfied the requirements to extend the term of both the ELs to the full nine year term. The Company acquired a 220 square kilometer multi-component 3-D seismic survey in 2012, and construction of an all season access road was completed in 2014. In 2016, the Company was awarded a Significant Discovery Declaration (“SDD”) on 545 sections (150,000 hectares) of land north of the Gambill Fault on EL 494 as part of the Conoco Phillips Dodo Canyon E-76 SDD application. Additionally, five sections of land were granted Significant Discovery License status earlier in 2016 based on the MGM East MacKay I-78 well on a thin strip of land south of the Gambill Fault. No activity is planned in 2017.

 

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Distribution of Oil and Gas Production

Crude Oil and NGL

The Company provides heavy crude oil feedstock to its Upgrader and its Asphalt Refinery, which are located in Lloydminster, Alberta/Saskatchewan. The Upgrader and Asphalt Refinery process the majority of the Company’s heavy crude oil production from the Lloydminster area. The Company also purchases third-party volumes. The Company markets heavy crude oil production directly to refiners located in the mid-west and eastern U.S. and Canada in addition to the BP-Husky Toledo Refinery. The Company markets its light and synthetic crude oil production to third-party refiners in Canada, the U.S. and Asia in addition to the Company’s Lima Refinery. NGLs are sold to petrochemical end users, retail and wholesale distributors and refiners in North America.

The Company markets third-party volumes of crude oil, synthetic crude oil and NGLs in addition to its own production. For a discussion of the Company’s distribution methods associated with crude oil and NGLs, see “Commodity Marketing”.

Natural Gas

The following table shows the distribution of the Company’s North American gross average daily natural gas production for the years indicated. The Company markets third-party natural gas production in addition to its own production. In North America, natural gas is sold to end users and retail and wholesale distributors.

 

     Years Ended December 31,  
     2016      2015      2014  
     (mmcf/day)  

Sales Distribution

        

United States

     164        218        183  

Canada

     79        113        138  
  

 

 

    

 

 

    

 

 

 
     243        331        321  
  

 

 

    

 

 

    

 

 

 

Sales to Aggregators

     8        —          —    

Internal Use (1)

     191        183        186  
  

 

 

    

 

 

    

 

 

 
     442        514        507  
  

 

 

    

 

 

    

 

 

 

 

(1) The Company consumes natural gas for fuel at several of its facilities.

 

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Disclosures of Oil and Gas Activities

Production History

 

     Year Ended      Three Months Ended  

Average Gross Daily Production(1)

   Dec. 31, 2016      Dec. 31, 2016      Sept. 30, 2016      Jun 30, 2016      Mar. 31, 2016  

Canada - Western Canada

           

Light and Medium Crude Oil (mbbls/day)

     23.4        15.1        16.5        29.6        33.0  

Heavy Crude Oil (mbbls/day)

     54.1        48.4        49.5        57.5        61.5  

Bitumen (mbbls/day)(2)

     97.4        115.3        103.6        88.0        81.8  

Conventional Natural Gas (mmcf/day)

     442.4        406.0        414.2        441.5        508.7  

NGL (mbbls/day)

     8.0        7.3        7.9        8.0        8.8  

Canada - Atlantic Region

              

Light and Medium Crude Oil (mbbls/day)

     33.1        34.3        24.8        32.7        40.5  

China - Asia Pacific Region(3)

              

Light and Medium Crude Oil (mbbls/day)

     6.6        5.5        6.3        7.1        7.4  

Conventional Natural Gas (mmcf/day)

     113.5        149.4        107.1        87.3        109.9  

NGL (mbbls/day)

     6.0        8.6        5.5        4.8        5.2  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Gross Production (mboe/day)

     321.2        327.0        301.0        315.8        341.3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
    

 

Year Ended

     Three Months Ended  

Average Gross Daily Production

   Dec. 31, 2015      Dec. 31, 2015      Sept. 30, 2015      Jun 30, 2015      Mar. 31, 2015  

Canada - Western Canada

              

Light and Medium Crude Oil (mbbls/day)

     36.4        34.4        35.0        37.3        38.8  

Heavy Crude Oil (mbbls/day)

     69.1        66.7        67.9        70.0        71.9  

Bitumen (mbbls/day)(2)

     63.1        79.0        66.7        50.3        55.7  

Conventional Natural Gas (mmcf/day)

     513.9        507.9        505.0        518.8        524.2  

NGL (mbbls/day)

     8.8        8.6        8.4        8.7        9.7  

Canada - Atlantic Region

              

Light and Medium Crude Oil (mbbls/day)

     36.8        43.5        29.6        32.6        41.7  

China - Asia Pacific Region(3)

              

Light and Medium Crude Oil (mbbls/day)

     7.3        6.4        7.5        7.4        8.0  

Conventional Natural Gas (mmcf/day)

     175.1        152.8        152.7        202.8        192.8  

NGL (mbbls/day)

     9.4        8.3        8.3        10.3        10.7  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Gross Production (mboe/day)

     345.7        357.0        333.0        336.9        356.0  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
    

 

Year Ended

     Three Months Ended  

Average Gross Daily Production

   Dec. 31, 2014      Dec. 31, 2014      Sept. 30, 2014      Jun 30, 2014      Mar. 31, 2014  

Canada - Western Canada

              

Light and Medium Crude Oil (mbbls/day)

     41.8        40.7        41.4        40.5        44.9  

Heavy Crude Oil (mbbls/day)

     76.8        77.5        76.1        78.1        75.5  

Bitumen (mbbls/day)(2)

     54.6        55.7        56.2        54.6        52.0  

Conventional Natural Gas (mmcf/day)

     506.8        521.3        509.3        490.6        505.9  

NGL (mbbls/day)

     9.8        10.2        9.1        9.6        10.2  

Canada - Atlantic Region

              

Light and Medium Crude Oil (mbbls/day)

     44.6        43.4        37.3        47.6        50.3  

China - Asia Pacific Region(3)

              

Light and Medium Crude Oil (mbbls/day)

     4.8        7.4        2.7        0.3        8.6  

Conventional Natural Gas (mmcf/day)

     114.2        180.2        161.0        113.0        —    

NGL (mbbls/day)

     4.2        7.8        6.6        2.3        0.1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Gross Production (mboe/day)

     340.1        359.6        341.1        333.6        325.9  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Total production volumes for 2016, for each product type, are set forth in the Reconciliation of Gross Proved Plus Probable Reserves table.

 

(2) Bitumen includes production from heavy oil thermal developments and the Tucker thermal development located near Cold Lake, Alberta. Bitumen production includes heavy oil thermal average daily gross production of 65.4 mbbls/day, 48.4 mbbls/day and 43.8 mbbls/day for the years ended December 31, 2016, 2015 and 2014, respectively.

 

(3)  Reported production volumes include the Company’s entitlement share of production from the Liwan Gas Project which was approximately 76 percent until late May 2015 and then reduced to its equity interest of 49 percent, reflecting the completion of exploration cost recoveries from the Liwan 3-1 field which were originally funded solely by the Company.

 

AIF 2016    Page 28


Table of Contents

Operating Netback Analysis(1)(2)

The following tables show the Company’s netback analysis by product and area:

 

     Year Ended      Three Months Ended  

Average Per Unit Amounts

   Dec 31, 2016      Dec 31, 2016      Sept 30, 2016      June 30, 2016      Mar 31, 2016  

Company Total(3)

              

Sales volume (mboe/day)

     321.2        327.0        301.0        315.8        341.3  

Gross Revenue ($/boe)(4)

   $ 33.08      $ 39.90      $ 33.11      $ 34.59      $ 25.02  

Royalties ($/boe)

   $ 2.60      $ 3.46      $ 2.01      $ 3.12      $ 1.74  

Production and Operating Costs ($/boe)(4)

   $ 14.04      $ 13.92      $ 15.15      $ 13.90      $ 13.31  

Transportation Costs ($/boe)(5)

   $ 0.25      $ 0.20      $ 0.25      $ 0.27      $ 0.29  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback ($/boe)

   $ 16.19      $ 22.32      $ 15.70      $ 17.30      $ 9.68  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Light and Medium Crude Oil ($/bbl)(3)

              

Canada - Western Canada

              

Gross Revenue(4)

   $ 40.95      $ 50.88      $ 46.01      $ 48.86      $ 26.72  

Royalties

   $ 3.85      $ 5.06      $ 3.48      $ 3.68      $ 3.63  

Production and Operating Costs(4)

   $ 26.92      $ 34.42      $ 28.86      $ 24.21      $ 24.91  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 10.18      $ 11.40      $ 13.67      $ 20.97      ($ 1.82
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Canada - Atlantic Canada

              

Gross Revenue

   $ 60.01      $ 69.19      $ 61.05      $ 61.83      $ 50.00  

Royalties

   $ 8.70      $ 11.92      $ 7.14      $ 10.44      $ 5.51  

Production and Operating Costs

   $ 18.48      $ 14.85      $ 28.07      $ 20.27      $ 14.20  

Transportation Costs(5)

   $ 2.46      $ 1.93      $ 3.01      $ 2.57      $ 2.47  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 30.37      $ 40.49      $ 22.83      $ 28.55      $ 27.82  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Canada - Total

              

Gross Revenue(4)

   $ 50.66      $ 62.28      $ 53.24      $ 54.32      $ 38.19  

Royalties

   $ 6.69      $ 9.84      $ 5.67      $ 7.23      $ 4.67  

Production and Operating Costs(4)

   $ 21.98      $ 20.80      $ 28.39      $ 22.14      $ 19.01  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 21.99      $ 31.64      $ 19.18      $ 24.95      $ 14.51  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

China

              

Gross Revenue

   $ 54.98      $ 68.65      $ 54.35      $ 60.34      $ 40.62  

Royalties

   $ 3.68      $ 4.68      $ 3.75      $ 4.17      $ 2.48  

Production and Operating Costs

   $ 11.68      $ 14.19      $ 10.27      $ 14.27      $ 8.52  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 39.62      $ 49.78      $ 40.33      $ 41.90      $ 29.62  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

              

Gross Revenue(4)

   $ 51.11      $ 62.91      $ 53.34      $ 54.90      $ 38.41  

Royalties

   $ 6.38      $ 9.30      $ 5.41      $ 6.92      $ 4.46  

Production and Operating Costs(4)

   $ 20.91      $ 20.14      $ 25.98      $ 21.34      $ 18.06  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 23.82      $ 33.47      $ 21.95      $ 26.64      $ 15.89  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Heavy Crude Oil ($/bbl)

              

Canada - Western Canada

              

Gross Revenue(4)

   $ 30.50      $ 36.30      $ 35.04      $ 34.88      $ 18.12  

Royalties

   $ 2.67      $ 3.55      $ 3.06      $ 2.89      $ 1.42  

Production and Operating Costs(4)

   $ 18.58      $ 21.90      $ 20.47      $ 16.09      $ 16.35  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 9.25      $ 10.85      $ 11.51      $ 15.90      $ 0.35  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Bitumen ($/bbl)

              

Canada - Western Canada

              

Gross Revenue(4)(5)

   $ 27.63      $ 33.80      $ 29.53      $ 30.95      $ 12.83  

Royalties

   $ 1.49      $ 2.04      $ 0.85      $ 2.41      $ 0.53  

Production and Operating Costs(4)

   $ 10.94      $ 12.30      $ 11.69      $ 9.00      $ 10.44  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 15.20      $ 19.46      $ 16.99      $ 19.54      $ 1.86  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
              

 

AIF 2016    Page 29


Table of Contents
     Year Ended     Three Months Ended  

Average Per Unit Amounts

   Dec 31, 2016     Dec 31, 2016      Sept 30, 2016     June 30, 2016     Mar 31, 2016  

Conventional Natural Gas ($/mcf)(3)

           

Canada - Western Canada

           

Gross Revenue(4)(6)

   $ 2.06     $ 2.92      $ 2.24     $ 1.24     $ 1.92  

Royalties(6)(7)

   ($ 0.04   $ 0.04      ($ 0.06   $ 0.02     ($ 0.11

Production and Operating Costs(4)

   $ 1.93     $ 1.76      $ 2.02     $ 2.10     $ 1.83  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Operating netback

   $ 0.17     $ 1.12      $ 0.28     ($ 0.88   $ 0.20  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

China

           

Gross Revenue

   $ 13.58     $ 13.10      $ 10.86     $ 14.81     $ 15.96  

Royalties

   $ 0.72     $ 0.68      $ 0.57     $ 0.78     $ 0.82  

Production and Operating Costs

   $ 1.17     $ 0.87      $ 1.20     $ 1.38     $ 1.39  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Operating netback

   $ 11.69     $ 11.55      $ 9.09     $ 12.65     $ 13.75  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total

           

Gross Revenue(4)

   $ 4.40     $ 5.65      $ 3.99     $ 3.46     $ 4.41  

Royalties

   $ 0.12     $ 0.22      $ 0.08     $ 0.10     $ 0.07  

Production and Operating Costs(4)

   $ 1.77     $ 1.52      $ 1.85     $ 1.99     $ 1.75  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Operating netback

   $ 2.51     $ 3.91      $ 2.06     $ 1.37     $ 2.59  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Natural Gas Liquids ($/bbl)(3)

           

Canada - Western Canada

           

Gross Revenue(4)

   $ 31.14     $ 38.78      $ 29.18     $ 31.09     $ 26.59  

Royalties

   $ 7.59     $ 10.01      $ 7.22     $ 7.77     $ 5.77  

Production and Operating Costs(4)

   $ 11.39     $ 10.29      $ 11.92     $ 12.56     $ 10.84  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Operating netback

   $ 12.16     $ 18.48      $ 10.04     $ 10.76     $ 9.98  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

China

           

Gross Revenue

   $ 47.14     $ 53.04      $ 44.83     $ 45.94     $ 40.92  

Royalties

   $ 2.65     $ 3.00      $ 2.57     $ 2.59     $ 2.25  

Production and Operating Costs

   $ 7.14     $ 5.38      $ 7.31     $ 8.44     $ 8.34  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Operating netback

   $ 37.35     $ 44.66      $ 34.95     $ 34.91     $ 30.33  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total

           

Gross Revenue(4)

   $ 38.01     $ 46.47      $ 35.62     $ 36.68     $ 31.89  

Royalties

   $ 5.45     $ 6.22      $ 5.29     $ 5.77     $ 4.46  

Production and Operating Costs(4)

   $ 9.57     $ 7.64      $ 10.03     $ 11.01     $ 9.92  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Operating netback

   $ 22.99     $ 32.61      $ 20.30     $ 19.90     $ 17.51  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) The operating netback includes results from Upstream Exploration and Production and excludes results from Upstream Infrastructure and Marketing. Operating netback is a non-GAAP measure. Refer to the Reader Advisories for further details.

 

(2)  During 2016, Husky completed the sale of 65% of its ownership interest in select midstream assets. These assets are held by HMLP, in which Husky has a 35% investment. The investment is considered a joint venture and is prospectively being accounted for using the equity method.

 

(3)  Includes associated co-products converted to boe and mcf.

 

(4) Transportation expenses for Western Canada production has been deducted from both prices received (i.e., gross revenue) and production and operating costs to reflect the actual price received at the oil and gas lease.

 

(5)  Includes offshore transportation costs shown separately from gross revenue. During the first quarter of 2016, the Company reclassified Oil Sands transportation costs to net against gross revenue. Prior periods have not been restated.

 

(6)  Includes sulphur sales revenues/royalties.

 

(7) Alberta Gas Cost Allowance reported exclusively as gas royalties.

 

AIF 2016    Page 30


Table of Contents
     Year Ended      Three Months Ended  

Average Per Unit Amounts

   Dec 31, 2015      Dec 31, 2015      Sept 30, 2015      June 30, 2015      Mar 31, 2015  

Company Total(2)

              

Sales volume (mboe/day)

     345.7        357.0        333.0        336.9        356.0  

Gross Revenue ($/boe)(3)

   $ 41.06      $ 34.89      $ 39.45      $ 49.50      $ 40.84  

Royalties ($/boe)

   $ 3.43      $ 2.60      $ 2.70      $ 4.37      $ 4.04  

Production and Operating Costs ($/boe)(3)

   $ 15.14      $ 14.51      $ 15.52      $ 15.72      $ 14.87  

Transportation Costs ($/boe)(4)

   $ 0.49      $ 0.50      $ 0.51      $ 0.48      $ 0.48  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback ($/boe)

   $ 22.00      $ 17.28      $ 20.72      $ 28.93      $ 21.45  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Light and Medium Crude Oil ($/bbl)(2)

              

Canada - Western Canada

              

Gross Revenue(3)

   $ 48.49      $ 42.60      $ 45.33      $ 61.55      $ 42.98  

Royalties

   $ 5.30      $ 4.86      $ 4.74      $ 5.90      $ 5.61  

Production and Operating Costs(3)

   $ 26.92      $ 27.96      $ 25.04      $ 27.04      $ 27.58  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 16.27      $ 9.78      $ 15.55      $ 28.61      $ 9.79  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Canada - Atlantic Canada

              

Gross Revenue

   $ 65.89      $ 54.12      $ 64.98      $ 79.25      $ 68.55  

Royalties

   $ 7.43      $ 5.26      $ 4.39      $ 10.55      $ 9.48  

Production and Operating Costs

   $ 16.76      $ 15.31      $ 20.94      $ 19.20      $ 13.36  

Transportation Costs(4)

   $ 2.58      $ 2.19      $ 3.14      $ 2.69      $ 2.50  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 39.12      $ 31.36      $ 36.51      $ 46.81      $ 43.21  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Canada - Total

              

Gross Revenue(3)

   $ 55.94      $ 47.81      $ 52.87      $ 68.55      $ 54.92  

Royalties

   $ 6.37      $ 5.08      $ 4.57      $ 8.07      $ 7.61  

Production and Operating Costs(3)

   $ 21.81      $ 20.90      $ 23.17      $ 23.39      $ 20.22  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 27.76      $ 21.83      $ 25.13      $ 37.09      $ 27.09  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

China(5)

              

Gross Revenue

   $ 60.80      $ 52.69      $ 53.54      $ 71.75      $ 64.00  

Royalties

   $ 3.12      $ 3.78      $ 0.73      $ 4.10      $ 3.40  

Production and Operating Costs

   $ 11.71      $ 13.53      $ 11.64      $ 9.67      $ 12.13  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 45.97      $ 35.38      $ 41.17      $ 57.98      $ 48.47  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

              

Gross Revenue(3)

   $ 56.37      $ 48.18      $ 52.94      $ 68.85      $ 55.73  

Royalties

   $ 6.07      $ 4.99      $ 4.17      $ 7.69      $ 7.23  

Production and Operating Costs(3)

   $ 20.90      $ 20.34      $ 21.97      $ 22.12      $ 19.49  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 29.40      $ 22.85      $ 26.80      $ 39.04      $ 29.01  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Heavy Crude Oil ($/bbl)

              

Canada - Western Canada

              

Gross Revenue(3)

   $ 37.16      $ 28.71      $ 36.51      $ 50.21      $ 32.97  

Royalties

   $ 4.44      $ 2.62      $ 4.02      $ 6.11      $ 4.93  

Production and Operating Costs(3)

   $ 18.16      $ 18.30      $ 18.09      $ 17.57      $ 18.88  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 14.56      $ 7.79      $ 14.40      $ 26.53      $ 9.16  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Bitumen ($/bbl)

              

Canada - Western Canada

              

Gross Revenue(3)(4)

   $ 34.47      $ 25.67      $ 33.86      $ 48.45      $ 34.97  

Royalties

   $ 2.92      $ 1.39      $ 3.30      $ 4.33      $ 3.40  

Production and Operating Costs(3)

   $ 14.94      $ 12.14      $ 15.19      $ 18.75      $ 15.16  

Transportation Costs(4)

   $ 1.20      $ 1.08      $ 1.14      $ 1.46      $ 1.22  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating netback

   $ 15.41      $ 11.06      $ 14.23      $ 23.91      $ 15.19  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

AIF 2016    Page 31


Table of Contents
     Year Ended     Three Months Ended  

Average Per Unit Amounts

   Dec 31, 2015     Dec 31, 2015     Sept 30, 2015     June 30, 2015     Mar 31, 2015  

Conventional Natural Gas ($/mcf)(2)

          

Canada - Western Canada

          

Gross Revenue(3)(6)

   $ 2.67     $ 2.43     $ 2.77     $ 2.76     $ 2.81  

Royalties(6)(7)

   ($ 0.08   ($ 0.03   ($ 0.23   ($ 0.04     —    

Production and Operating Costs(3)

   $ 2.08     $ 2.01     $ 2.10     $ 2.05     $ 2.13  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating netback

   $ 0.67     $ 0.45     $ 0.90     $ 0.75     $ 0.68  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

China(5)

          

Gross Revenue

   $ 14.98     $ 15.76     $ 15.51     $ 14.50     $ 14.43  

Royalties

   $ 0.81     $ 0.96     $ 0.81     $ 0.75     $ 0.76  

Production and Operating Costs

   $ 0.77     $ 0.81     $ 0.90     $ 0.92     $ 0.51  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating netback

   $ 13.40     $ 13.99     $ 13.80     $ 12.83     $ 13.16  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

          

Gross Revenue(3)

   $ 5.80     $ 5.51     $ 5.76     $ 6.09     $ 5.96  

Royalties

   $ 0.13     $ 0.18     $ 0.04     $ 0.19     $ 0.21  

Production and Operating Costs(3)

   $ 1.74     $ 1.72     $ 1.82     $ 1.75     $ 1.69  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating netback

   $ 3.93     $ 3.61     $ 3.90     $ 4.15     $ 4.06  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Natural Gas Liquids ($/bbl)(2)

          

Canada - Western Canada

          

Gross Revenue(3)

   $ 34.08     $ 32.46     $ 32.53     $ 38.84     $ 32.66  

Royalties

   $ 7.75     $ 7.55     $ 8.41     $ 7.96     $ 7.18  

Production and Operating Costs(3)

   $ 12.26     $ 11.99     $ 12.25     $ 12.26     $ 12.55  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating netback

   $ 14.07     $ 12.92     $ 11.87     $ 18.62     $ 12.93  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

China(5)

          

Gross Revenue

   $ 56.99     $ 52.91     $ 53.92     $ 62.65     $ 56.71  

Royalties

   $ 3.19     $ 2.99     $ 2.75     $ 3.46     $ 3.16  

Production and Operating Costs

   $ 4.78     $ 5.09     $ 5.36     $ 5.58     $ 3.24  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating netback

   $ 49.02     $ 44.83     $ 45.81     $ 53.61     $ 50.31  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

          

Gross Revenue(3)

   $ 45.88     $ 42.46     $ 43.18     $ 51.97     $ 45.29  

Royalties

   $ 5.39     $ 5.31     $ 5.74     $ 5.51     $ 5.07  

Production and Operating Costs(3)

   $ 8.39     $ 8.60     $ 8.82     $ 8.58     $ 7.66  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating netback

   $ 32.10     $ 28.55     $ 28.62     $ 37.88     $ 32.56  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) The operating netback includes results from Upstream Exploration and Production and excludes results from Upstream Infrastructure and Marketing. Operating netback is a non-GAAP measure. Refer to the Reader Advisories for further details.

 

(2)  Includes associated co-products converted to boe and mcf.

 

(3) Transportation expenses for Western Canada production has been deducted from both prices received (i.e., gross revenue) and production and operating costs to reflect the actual price received at the oil and gas lease.

 

(4) Includes offshore transportation costs shown separately from gross revenue. During the first quarter of 2016, the Company reclassified Oil Sands transportation costs to net against gross revenue. Prior periods have not been restated.

 

(5) Reported production volumes include the Company’s entitlement share of production from the Liwan Gas Project which was approximately 76 percent until late May 2015 and then reduced to its equity interest of 49 percent, reflecting the completion of exploration cost recoveries from the Liwan 3-1 field which were originally funded solely by the Company.

 

(6)  Includes sulphur sales revenues/royalties.

 

(7) Alberta Gas Cost Allowance reported exclusively as gas royalties.

 

AIF 2016    Page 32


Table of Contents

Producing and Non-Producing Wells(1)(2)(3)

Producing Wells

 

     Oil Wells      Natural Gas Wells      Total  
     Gross      Net      Gross      Net      Gross      Net  

Canada

                 

Alberta

     2,513        2,161        4,138        2,917        6,651        5,078  

Saskatchewan

     3,031        2,933        226        224        3,257        3,157  

British Columbia

     3        1        273        250        276        251  

Newfoundland

     33        14        —          —          33        14  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     5,580        5,109        4,637        3,391        10,217        8,500  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

International

                 

China

     32        13        10        5        42        18  

Libya

     —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     32        13        10        5        42        18  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As at December 31, 2016

     5,612        5,122        4,647        3,396        10,259        8,518  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Canada

                 

Alberta

     3,929        3,157        5,220        3,774        9,149        6,931  

Saskatchewan

     5,380        4,535        1,262        1,139        6,642        5,674  

British Columbia

     195        57        297        263        492        320  

Newfoundland

     31        12        —          —          31        12  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     9,535        7,761        6,779        5,176       
16,314
 
     12,937  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

International

                 

China

     32        13        10        5        42        18  

Libya

     3        1        —          —          3        1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     35        14        10        5        45        19  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As at December 31, 2015

     9,570        7,775        6,789        5,181        16,359        12,956  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Canada

                 

Alberta

     4,208        3,444        5,312        3,846        9,520        7,290  

Saskatchewan

     6,273        5,356        1,345        1,220        7,618        6,576  

British Columbia

     199        57        296        260        495        317  

Newfoundland

     30        11        —          —          30        11  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     10,710        8,868        6,953        5,326        17,663        14,194  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

International

                 

China

     28        11        10        5        38        16  

Libya

     3        1        —          —          3        1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     31        12        10        5        41        17  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As at December 31, 2014

     10,741        8,880        6,963        5,331        17,704        14,211  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Non-Producing Wells

 

     2016  
     Oil Wells      Natural Gas Wells      Total  
     Gross      Net      Gross      Net      Gross      Net  

Alberta

     3,106        2,895        1,630        1,339        4,736        4,234  

Saskatchewan

     4,247        4,081        216        193        4,463        4,274  

British Columbia

     —          —          59        40        59        40  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     7,353        6,976        1,905        1,572        9,258        8,548  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  The number of gross wells is the total number of wells in which the Company owns a working interest. The number of net wells is the sum of the fractional interests owned in the gross wells. Productive wells are those producing or capable of producing at December 31, 2016.

 

(2)  The above table does not include producing wells in which the Company has no working interest but does have a royalty interest. At December 31, 2016, the Company had a royalty interest in 1,221 wells, of which 652 were oil producers and 569 were gas producers.

 

(3)  For purposes of the table, multiple completions are counted as a single well. Where one of the completions in a given well is an oil completion, the well is classified as an oil well. In 2016, there were 1,129 gross and 1,036 net oil wells and 191 gross and 149 net natural gas wells that were completed in two or more formations and from which production is not commingled.

 

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Landholdings - Developed Acreage

 

(thousands of acres)

   Gross      Net  

As at December 31, 2016

     

Western Canada

     

Alberta

     3,201        2,624  

Saskatchewan

     502        455  

British Columbia

     145        122  

Manitoba

     —          —    
  

 

 

    

 

 

 
     3,848        3,201  

Atlantic Region

     54        20  
  

 

 

    

 

 

 
     3,902        3,221  

China

     17        7  

Libya

     7        2  
  

 

 

    

 

 

 

Total

     3,926        3,230  
  

 

 

    

 

 

 

As at December 31, 2015

     

Western Canada

     

Alberta

     4,552        2,904  

Saskatchewan

     814        647  

British Columbia

     184        144  

Manitoba

     2        —    
  

 

 

    

 

 

 
     5,552        3,695  

Atlantic Region

     54        20  
  

 

 

    

 

 

 
     5,606        3,715  

China

     17        7  

Libya

     7        2  
  

 

 

    

 

 

 

Total

     5,630        3,724  
  

 

 

    

 

 

 

As at December 31, 2014

     

Western Canada

     

Alberta

     4,574        2,924  

Saskatchewan

     806        638  

British Columbia

     185        145  

Manitoba

     3        —    
  

 

 

    

 

 

 
     5,568        3,707  

Atlantic Region

     57        20  
  

 

 

    

 

 

 
     5,625        3,727  

China

     17        7  

Libya

     7        2  
  

 

 

    

 

 

 

Total

     5,649        3,736  
  

 

 

    

 

 

 

 

AIF 2016    Page 34


Table of Contents

Landholdings - Undeveloped Acreage

 

(thousands of acres)

   Gross      Net  

As at December 31, 2016

     

Western Canada

     

Alberta

     3,190        2,733  

Saskatchewan

     670        629  

British Columbia

     575        463  

Manitoba

     —          —    
  

 

 

    

 

 

 
     4,435        3,825  

Northwest Territories and Arctic

     483        466  

Atlantic Region

     2,354        1,191  
  

 

 

    

 

 

 
     7,272        5,482  

United States

     —          —    

China

     95        46  

Indonesia

     3,589        3,216  

Greenland

     —          —    

Taiwan

     1,904        1,428  
  

 

 

    

 

 

 

Total

     12,860        10,172  
  

 

 

    

 

 

 

As at December 31, 2015

     

Western Canada

     

Alberta

     4,231        2,978  

Saskatchewan

     1,467        1,329  

British Columbia

     644        506  

Manitoba

     2        1  
  

 

 

    

 

 

 
     6,344        4,814  

Northwest Territories and Arctic

     483        466  

Atlantic Region

     2,675        1,278  
  

 

 

    

 

 

 
     9,502        6,558  

United States

     2        —    

China

     72        35  

Indonesia

     3,589        3,216  

Greenland

     5,205        4,555  

Taiwan

     1,904        1,428  
  

 

 

    

 

 

 

Total

     20,274        15,792  
  

 

 

    

 

 

 

As at December 31, 2014

     

Western Canada

     

Alberta

     4,529        3,247  

Saskatchewan

     1,708        1,550  

British Columbia

     743        583  

Manitoba

     3        1  
  

 

 

    

 

 

 
     6,983        5,381  

Northwest Territories and Arctic

     483        466  

Atlantic Region

     2,698        1,295  
  

 

 

    

 

 

 
     10,164        7,142  

United States

     89        29  

China

     56        27  

Indonesia

     1,559        1,186  

Greenland

     5,205        4,555  

Taiwan

     2,545        1,909  
  

 

 

    

 

 

 

Total

     19,618        14,848  
  

 

 

    

 

 

 

 

AIF 2016    Page 35


Table of Contents

Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

The Company has commitments totaling approximately $90 million related to exploration to be completed in the Atlantic region between 2021 and 2025. In addition, the Company has approximately $48 million of commitments related to exploration in the North West Territories by 2021. Failure to complete the necessary work commitment may result in the Company forfeiting the right to further exploration activity on the undeveloped land.

Approximately 324,784 acres, or less than six percent of the Company’s net undeveloped landholdings in Canada, will be subject to expiry in 2017.

The Company holds interests in a diverse portfolio of undeveloped petroleum assets in Western Canada, the Atlantic Region, China, Taiwan and Indonesia, the Canadian Northwest Territories and the Arctic. As part of its active portfolio management, the Company continually reviews the economic viability of its undeveloped properties using industry standard economic evaluation techniques and pricing and economic environment assumptions. Each year, as part of this active management process, some properties are selected for further development activities, while others are held in abeyance, sold, swapped or relinquished back to the mineral rights owner. There is no guarantee that commercial reserves will be discovered or developed on these properties.

Abandonment and Reclamation Costs

There are no significant abandonment or reclamation costs and no unusually high expected development costs or operating costs that have affected or that the Company reasonably expects to affect anticipated development or production activities on properties with no attributed reserves. For further information on abandonment and reclamation costs in respect of the Company’s properties, please refer to Note 16 of the Company’s audited consolidated financial statements for the year ended December 31, 2016.

 

AIF 2016    Page 36


Table of Contents

Drilling Activity - Number of Wells Drilled

 

     Year Ended December 31,  
     2016      2015      2014  
     Gross      Net      Gross      Net      Gross      Net  

Canada - Western Canada

                 

Exploration

                 

Oil

     15        15        5        4        53        44  

Gas

     —          —          4        1        9        6  

Dry

     —          —          1        1        3        3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     15        15        10        6        65        53  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Development

                 

Oil

     60        60        121        105        469        403  

Gas

     3        2        34        24        78        67  

Dry

     —          —          —          —          3        3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     63        62        155        129        550        473  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     78        77        165        135        615        527  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Canada - Atlantic Region

                 

Development

                 

Oil

     2.0        1.4        2.0        1.4        1.0        0.1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

China

                 

Development

                 

Oil

     —          —          1.0        0.4        —          —    

Gas

     —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     —          —          1.0        0.4        —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Indonesia

                 

Development

                 

Oil

     —          —          —          —          —          —    

Gas

     4.0        1.6        —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     4.0        1.6        —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Stratigraphic Test Wells

 

     2016      2015      2014  
     Gross      Net      Gross      Net      Gross      Net  

Canada - Western Canada

     —          —          —          —          6        6  

Canada - Atlantic Region

     3.0        1.0        5.0        1.8        2.0        1.0  

China

     —          —          —          —          —          —    

Indonesia

     —          —          —          —          1.0        0.4  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Service Wells

 

     2016      2015      2014  
     Gross      Net      Gross      Net      Gross      Net  

Canada - Western Canada

     31        31        38        35        121        121  

Canada - Atlantic Region

     —          —          —          —          2.0        0.9  

China

     —          —          —          —          —          —    

Indonesia

     —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

AIF 2016    Page 37


Table of Contents

Costs Incurred

 

     Total      Western
Canada
     Atlantic
Region
     Total
Canada
     United
States
     China      Indonesia      Libya  
     ($ millions)  

Property acquisition

                       

Unproven

     —          —          —          —          —          —          —          —    

Proven

     7        7        —          7        —          —          —          —    

Exploration

     63        25        34        59        —          4        —          —    

Development

     1,190        683        262        945        —          106        139        —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2016

     1,260        715        296        1,011        —          110        139        —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

     Total      Western
Canada
     Atlantic
Region
     Total
Canada
     United
States
     China     Indonesia      Libya  
     ($ millions)  

Property acquisition

                      

Unproven

     —          —          —          —          —          —         —          —    

Proven

     56        56        —          56        —          —         —          —    

Exploration

     249        38        208        246        —          (1     4        —    

Development

     1,932        1,525        342        1,867        —          31       34        —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

2015

     2,237        1,619        550        2,169        —          30       38        —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

     Total      Western
Canada
     Atlantic
Region
     Total
Canada
     United
States
     China      Indonesia      Libya  
     ($ millions)  

Property acquisition

                       

Unproven

     —          —          —          —          —          —          —          —    

Proven

     51        51        —          51        —          —          —          —    

Exploration

     375        260        98        358        —          12        5        —    

Development

     3,940        2,785        752        3,537        —          380        23        —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2014

     4,366        3,096        850        3,946        —          392        28        —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

AIF 2016    Page 38


Table of Contents

Oil and Gas Reserves Disclosures

Husky’s oil and gas reserves are estimated in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGEH”), and the reserves data disclosed conforms with the requirements of National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). All of Husky’s oil and gas reserves are prepared by internal reserves evaluation staff using a formalized process for determining, approving and booking reserves. This process requires all reserves evaluations to be done on a consistent basis using established definitions and guidelines. Approval of individually significant reserves changes requires review by an internal panel of expert geoscientists and qualified reserves evaluators. The Audit Committee of the Board of Directors has examined Husky’s procedures for assembling and reporting reserves data and other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has approved, on the recommendation of the Audit Committee, the content of Husky’s disclosure of its reserves data and other oil and gas information.

The following oil and gas reserves disclosure dated February 24, 2017 has been prepared in accordance with NI 51-101 effective December 31, 2016. The reserves information prepared in accordance with the rules of the U.S. Financial Accounting Standards Board (“FASB”) and the U.S. Securities Exchange Commission (“SEC”) (“U.S. Rules”) is included in the Company’s Form 40-F, which is available at www.sec.gov or on the Company’s website at www.huskyenergy.com. The material differences between reserves quantities disclosed under NI 51-101 and those disclosed under the U.S. Rules is that NI 51-101 requires the determination of reserves quantities to be based on forecast pricing assumptions whereas the U.S. Rules require the determination of reserves quantities to be based on constant price assumptions calculated using a 12 month average price for the year (sum of the benchmark price on the first calendar day of each month in the year divided by 12).

Note that the numbers in each column of the tables throughout this section may not add due to rounding. Unless otherwise noted in this document, all provided reserves estimates have an effective date of December 31, 2016.

Independent Audit or Evaluation of Oil and Gas Reserves

Sproule Associates Ltd. (“Sproule”), an independent firm of qualified oil and gas reserves evaluation engineers, was engaged to conduct an audit of Husky’s crude oil, natural gas and NGL reserves estimates. Sproule issued an audit opinion stating that Husky’s internally generated proved and probable reserves and net present values based on forecast and constant price assumptions are, in aggregate, reasonable, and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices as set out in the COGEH.

 

AIF 2016    Page 39


Table of Contents

Disclosure of Oil and Gas Information

Unless otherwise noted in this document, all provided reserves estimates have a preparation date of January 31, 2017 and an effective date of December 31, 2016 and are Husky’s total proved and probable reserves. Gross reserves or gross production are reserves or production attributable to Husky’s interest prior to deduction of royalties; net reserves or net production are reserves or production net of such royalties. Gross or net production reported refers to sales volume, unless otherwise indicated. Unless otherwise noted, production and reserves figures are stated on a gross basis. Unless otherwise indicated, oil and gas commodity prices are quoted after the effect of hedging gains and losses. Unless otherwise indicated, all financial information is in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board.

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

Bitumen reserves include reserves from thermal projects in Husky’s Lloydminster area. These projects contain oil that is lighter and less viscous than typical bitumen.

Disclosure of Exemption Under National Instrument 51-101

Husky sought and was granted by the Canadian Securities Administrators (“CSA”) an exemption from the requirement under NI 51-101 to involve independent qualified oil and gas reserves evaluators or auditors. Notwithstanding this exemption, the Company involves independent qualified reserves auditors as part of Husky’s corporate governance practices. Their involvement helps assure that the Company’s internal oil and gas reserves estimates are materially correct.

The reliability of Husky’s internally generated oil and gas reserves data is not materially less than would be afforded by Husky involving independent qualified reserves evaluators to evaluate the reserves data. Husky’s reserves are prepared within each business unit by Qualified Reserves Evaluators. These evaluators are also responsible for the management of the assets, and therefore their knowledge of, and experience with the reserves data, is superior to that of external reserves evaluators. Husky employs a number of quality assurance measures to ensure that reserves estimates are prepared in accordance with all requirements of applicable securities regulators and not influenced by self-interest or management activities of the internal reserves evaluation staff. Husky’s independent reserves auditor also reviews and assesses Husky’s reserves process to ensure that it is complete.

 

AIF 2016    Page 40


Table of Contents

Summary of Oil and Natural Gas Reserves

As at December 31, 2016

Forecast Prices and Costs

Canada

 

     Light & Medium
Crude Oil
(mmbbls)
     Heavy Crude Oil
(mmbbls)
     Bitumen
(mmbbls)
     Total Oil
(mmbbls)
 
     Gross      Net      Gross      Net      Gross      Net      Gross      Net  

Proved

                       

Developed Producing

     73.2        64.0        56.9        54.8        140.6        132.3        270.7        251.1  

Developed Non-producing

     2.1        1.6        6.0        5.6        19.3        17.5        27.4        24.7  

Undeveloped

     5.7        4.9        0.3        0.3        488.3        418.5        494.3        423.6  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     81.0        70.5        63.3        60.6        648.1        568.2        792.4        699.4  

Probable

     167.9        139.6        20.1        19.3        1,274.6        998.8        1,462.5        1,157.8  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Plus Probable

     248.9        210.1        83.3        80.0        1,922.7        1,567.0        2,254.9        1,857.1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     Conventional Natural
Gas
(bcf)
     Natural Gas Liquids
(mmbbls)
     Total (mmboe)                
     Gross      Net      Gross      Net      Gross      Net                

Proved

                       

Developed Producing

     1,162.5        1,088.5        41.1        32.5        505.5        465.0        

Developed Non-producing

     20.1        16.8        0.9        0.7        31.6        28.1        

Undeveloped

     334.2        282.0        3.2        2.5        553.1        473.1        

Total Proved

     1,516.9        1,387.3        45.1        35.7        1,090.3        966.3        

Probable

     423.1        365.0        8.2        5.9        1,541.2        1,224.5        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       

Total Proved Plus Probable

     1,939.9        1,752.3        53.3        41.5        2,631.5        2,190.7        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       
China                        
     Light & Medium
Crude Oil
(mmbbls)
     Heavy Crude Oil
(mmbbls)
     Bitumen
(mmbbls)
     Total Oil
(mmbbls)
 
     Gross      Net      Gross      Net      Gross      Net      Gross      Net  

Proved

                       

Developed Producing

     2.0        1.6        —          —          —          —          2.0        1.6  

Developed Non-producing

     —          —          —          —          —          —          —          —    

Undeveloped

     —          —          —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     2.0        1.6        —          —          —          —          2.0        1.6  

Probable

     —          —          —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Plus Probable

     2.0        1.6        —          —          —          —          2.0        1.6  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     Conventional Natural
Gas
(bcf)
     Natural Gas Liquids
(mmbbls)
     Total (mmboe)                
     Gross      Net      Gross      Net      Gross      Net                

Proved

                       

Developed Producing

     399.9        377.4        13.6        12.8        82.3        77.3        

Developed Non-producing

     —          —          —          —          —          —          

Undeveloped

     —          —          —          —          —          —          

Total Proved

     399.9        377.4        13.6        12.8        82.3        77.3        

Probable

     118.0        111.6        4.3        4.1        24.0        22.7        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       

Total Proved Plus Probable

     517.9        489.0        17.9        16.9        106.3        100.0        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       

 

AIF 2016    Page 41


Table of Contents

Indonesia

 

     Light & Medium
Crude Oil 
(mmbbls)
     Heavy Crude Oil
(mmbbls)
     Bitumen
(mmbbls)
     Total Oil
(mmbbls)
 
     Gross      Net      Gross      Net      Gross      Net      Gross      Net  

Proved

                       

Developed Producing

     —          —          —          —          —          —          —          —    

Developed Non-producing

     —          —          —          —          —          —          —          —    

Undeveloped

     —          —          —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     —          —          —          —          —          —          —          —    

Probable

     —          —          —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Plus Probable

     —          —          —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     Conventional Natural
Gas
(bcf)
     Natural Gas Liquids
(mmbbls)
     Total (mmboe)                
     Gross      Net      Gross      Net      Gross      Net                

Proved

                       

Developed Producing

     —          —          —          —          —          —          

Developed Non-producing

     167.2        126.1        7.2        4.9        35.0        25.9        

Undeveloped

     101.0        76.1        —          —          16.8        12.7        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       

Total Proved

     268.2        202.2        7.2        4.9        51.9        38.6        

Probable

     139.6        81.7        2.1        0.6        25.3        14.2        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       

Total Proved Plus Probable

     407.8        283.9        9.2        5.5        77.2        52.8        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       
Total                        
     Light & Medium
Crude Oil 
(mmbbls)
     Heavy Crude Oil
(mmbbls)
     Bitumen
(mmbbls)
     Total Oil
(mmbbls)
 
     Gross      Net      Gross      Net      Gross      Net      Gross      Net  

Proved

                       

Developed Producing

     75.2        65.6        56.9        54.8        140.6        132.3        272.7        252.7  

Developed Non-producing

     2.1        1.6        6.0        5.6        19.3        17.5        27.4        24.7  

Undeveloped

     5.7        4.9        0.3        0.3        488.3        418.5        494.3        423.6  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     83.0        72.1        63.3        60.6        648.1        568.2        794.4        701.0  

Probable

     167.9        139.6        20.1        19.3        1,274.6        998.8        1,462.5        1,157.8  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Plus Probable

     250.9        211.8        83.3        80.0        1,922.7        1,567.0        2,256.9        1,858.8  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     Conventional Natural
Gas
(bcf)
     Natural Gas Liquids
(mmbbls)
     Total (mmboe)                
     Gross      Net      Gross      Net      Gross      Net                

Proved

                       

Developed Producing

     1,562.5        1,465.9        54.7        45.3        587.8        542.4        

Developed Non-producing

     187.3        142.9        8.1        5.6        66.7        54.0        

Undeveloped

     435.2        358.1        3.2        2.5        570.0        485.8        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       

Total Proved

     2,185.0        1,966.8        65.9        53.4        1,224.4        1,082.2        

Probable

     680.6        558.3        14.5        10.6        1,590.5        1,261.4        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       

Total Proved Plus Probable

     2,865.7        2,525.1        80.4        64.0        2,814.9        2,343.6        
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

       

 

AIF 2016    Page 42


Table of Contents

Summary of Net Present Values of Future Net Revenue - Before Income Taxes and Discounted

As at December 31, 2016

Forecast Prices and Costs

Canada

 

     Before Income Taxes and Discounted at (%/year)      Unit Value
Discounted at 10%
 

($ millions)

   0%      5%      10%      15%      20%      ($/boe)  

Proved

                 

Developed Producing

     2,070        5,603        5,519        5,102        4,700        11.87  

Developed Non-producing

     66        244        297        306        298        10.56  

Undeveloped

     14,196        6,706        3,982        2,642        1,851        8.42  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     16,331        12,553        9,798        8,049        6,850        10.14  

Probable

     45,619        16,160        7,727        4,311        2,607        6.31  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Plus Probable

     61,950        28,713        17,525        12,360        9,456        8.00  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

China

 

     Before Income Taxes and Discounted at (%/year)      Unit Value
Discounted at 10%
 

($ millions)

   0%      5%      10%      15%      20%      ($/boe)  

Proved

                 

Developed Producing

     4,859        4,168        3,630        3,203        2,859        46.94  

Developed Non-producing

     —          —          —          —          —          —    

Undeveloped

     —          —          —          —          —          —