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))

707-8^th 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

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

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.

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 24^th 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

Document A

Form 40-F

Annual Information Form

For the Year Ended December 31, 2016

Husky Energy Inc.

Annual Information Form

For the Year Ended December 31, 2016

February 24, 2017

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

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.

AIF 2016 Page 1

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

AIF 2016 Page 2

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.

AIF 2016 Page 3

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.

AIF 2016 Page 4

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.

AIF 2016 Page 5

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.

AIF 2016 Page 6

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.

AIF 2016 Page 7

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.

AIF 2016 Page 8

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

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

AIF 2016 Page 19

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.

AIF 2016 Page 20

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.

AIF 2016 Page 21

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.

AIF 2016 Page 22

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.

AIF 2016 Page 23

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.

AIF 2016 Page 24

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.

AIF 2016 Page 25

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.

AIF 2016 Page 26

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.

AIF 2016 Page 27

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

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

	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

	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

	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

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.

AIF 2016 Page 33

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

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

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

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

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

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

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

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

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

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		—		—		—		—		—		—
Total Proved		4,859		4,168		3,630		3,203		2,859		46.94
Probable		1,483		998		692		493		360		30.48
Total Proved Plus Probable		6,342		5,166		4,322		3,696		3,219		43.20

Indonesia

	Before Income Taxes and Discounted at (%/year)										Unit Value Discounted at 10%
($ millions)	0%		5%		10%		15%		20%		($/boe)
Proved
Developed Producing		—		—		—		—		—		—
Developed Non-producing		702		559		458		384		328		17.67
Undeveloped		246		165		110		72		45		8.71
Total Proved		948		724		568		456		373		14.72
Probable		531		369		265		195		147		18.61
Total Proved Plus Probable		1,479		1,093		833		652		520		15.77

Total

	Before Income Taxes and Discounted at (%/year)										Unit Value Discounted at 10%
($ millions)	0%		5%		10%		15%		20%		($/boe)
Proved
Developed Producing		6,929		9,772		9,149		8,305		7,559		16.87
Developed Non-producing		768		802		755		690		627		13.97
Undeveloped		14,441		6,871		4,092		2,714		1,896		8.42
Total Proved		22,138		17,445		13,996		11,709		10,081		12.93
Probable		47,634		17,526		8,684		4,999		3,114		6.88
Total Proved Plus Probable		69,772		34,971		22,680		16,707		13,195		9.68

AIF 2016 Page 43

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

As at December 31, 2016

Forecast Prices and Costs

Canada
	After Income Taxes and Discounted at (%/year)
($ millions)	0%		5%		10%		15%		20%
Proved
Developed Producing		1,610		4,128		4,040		3,724		3,426
Developed Non-producing		70		196		232		236		229
Undeveloped		10,349		4,786		2,773		1,786		1,206
Total Proved		12,029		9,110		7,046		5,746		4,860
Probable		33,242		11,528		5,354		2,872		1,647
Total Proved Plus Probable		45,271		20,637		12,400		8,618		6,507
China
	After Income Taxes and Discounted at (%/year)
($ millions)	0%		5%		10%		15%		20%
Proved
Developed Producing		4,251		3,651		3,183		2,811		2,511
Developed Non-producing		—		—		—		—		—
Undeveloped		—		—		—		—		—
Total Proved		4,251		3,651		3,183		2,811		2,511
Probable		1,179		792		548		389		283
Total Proved Plus Probable		5,431		4,443		3,730		3,200		2,793
Indonesia
	After Income Taxes and Discounted at (%/year)
($ millions)	0%		5%		10%		15%		20%
Proved
Developed Producing		—		—		—		—		—
Developed Non-producing		542		439		366		311		269
Undeveloped		217		144		95		61		36
Total Proved		759		584		461		371		304
Probable		405		287		210		157		120
Total Proved Plus Probable		1,164		871		671		529		424
Total
	After Income Taxes and Discounted at (%/year)
($ millions)	0%		5%		10%		15%		20%
Proved
Developed Producing		5,861		7,778		7,223		6,535		5,936
Developed Non-producing		612		635		598		547		497
Undeveloped		10,566		4,931		2,869		1,847		1,242
Total Proved		17,039		13,344		10,689		8,929		7,675
Probable		34,826		12,607		6,112		3,418		2,049
Total Proved Plus Probable		51,866		25,951		16,801		12,346		9,725

AIF 2016 Page 44

Total Future Net Revenue for Total Proved Plus Probable Reserves - Undiscounted

As at December 31, 2016

Forecast Prices and Costs

($ millions)	Revenue		Royalties		Operating Costs		Develop- ment Costs		Abandon- ment and Reclama- tion Costs		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
Canada
Total Proved		62,433		8,534		22,947		6,734		7,887		16,331		4,302		12,029
Total Proved Plus Probable		188,784		35,906		57,625		25,175		8,129		61,950		16,679		45,271
China
Total Proved		5,640		—		527		46		208		4,859		608		4,251
Total Proved Plus Probable		7,280		—		684		46		208		6,342		912		5,431
Indonesia
Total Proved		2,205		—		1,144		113		—		948		189		759
Total Proved Plus Probable		3,156		—		1,457		220		—		1,479		316		1,164
Total
Total Proved		70,278		8,534		24,619		6,892		8,095		22,138		5,099		17,039
Total Proved Plus Probable		199,220		35,906		59,766		25,440		8,336		69,772		17,906		51,866

Future Net Revenue by Product Type

As at December 31, 2016

Forecast Prices and Costs

	Future Net Revenue Before Income Taxes (discounted at 10%/year)(1)
	Canada				China				Indonesia				Total
	($ millions)		($/boe)		($ millions)		($/boe)		($ millions)		($/boe)		($ millions)		($/boe)
Total Proved
Light & Medium Crude Oil		1,547		11.19		68		42.35		—		—		1,616		11.55
Heavy Crude Oil		206		3.34		—		—		—		—		206		3.34
Bitumen		7,076		12.45		—		—		—		—		7,076		12.45
Total Oil		8,830		11.50		68		42.35		—		—		8,898		11.56
Conventional Natural Gas		968		4.89		3,562		47.04		568		14.72		5,098		16.31
Total Proved		9,798		10.14		3,630		46.94		568		14.72		13,996		12.93
Total Proved Plus Probable
Light & Medium Crude Oil		3,231		11.43		68		42.35		—		—		3,299		11.60
Heavy Crude Oil		551		6.79		—		—		—		—		551		6.79
Bitumen		12,411		7.92		—		—		—		—		12,411		7.92
Total Oil		16,193		8.39		68		42.35		—		—		16,261		8.42
Conventional Natural Gas		1,332		5.13		4,254		43.22		833		15.77		6,419		15.61
Total Proved Plus Probable		17,525		8.00		4,322		43.20		833		15.77		22,680		9.68

⁽¹⁾ By-products, including solution gas, NGL and other associated by-products, are included in their main product group (natural gas or oil).

AIF 2016 Page 45

Pricing Assumptions

Except as noted below, the pricing assumptions disclosed in the following table were derived using the industry averages prescribed by McDaniel and Associates Consultants Ltd., Sproule Associates Limited, and GLJ Petroleum Consultants Ltd. China and Indonesia gas prices are derived from the GSAs specific to each set of projects. For historical prices realized during 2016, see the section “Disclosure of Oil and Gas Activities” in this AIF.

	Light Crude Oil						Medium Crude Oil		Heavy Crude Oil
	WTI (U.S. $/bbl)		Brent (U.S. $/bbl)		Edmonton (Cdn $/bbl)		Hardisty Bow River (Cdn $/bbl)		Hardisty Heavy API (Cdn $/bbl)
Historical
2016		43.32		43.69		52.99		39.55		32.61
Forecast
2017		55.00		56.00		68.24		54.06		47.24
2018		60.90		61.90		73.16		59.67		52.51
2019		65.47		66.47		76.25		63.48		56.16
2020		69.13		70.50		79.37		66.27		58.75
2021		73.21		74.58		82.56		69.22		61.45
2022		75.19		76.56		84.85		71.34		63.43
2023		77.19		78.56		87.15		73.45		65.48
2024		79.23		80.60		89.50		75.62		67.47
2025		81.28		82.68		91.89		77.82		69.43
2026		83.39		84.98		94.01		80.00		71.65
Thereafter(1)
	Bitumen		Natural Gas		Natural Gas Liquids
	Hardisty WCS (Cdn $/bbl)		NIT (Cdn $/GJ)		Edmonton Propane (Cdn $/bbl)		Edmonton Butane (Cdn $/bbl)		Edmonton Condensate (Cdn $/bbl)
Historical
2016		39.05		1.98		12.72		33.76		55.59
Forecast
2017		53.38		3.43		24.82		47.01		70.95
2018		58.95		3.17		26.16		52.53		75.40
2019		62.70		3.26		27.70		54.57		78.72
2020		65.48		3.67		29.10		57.49		81.52
2021		68.39		3.86		30.61		60.83		84.77
2022		70.49		3.97		31.80		62.55		87.17
2023		72.58		4.11		33.01		64.24		89.44
2024		74.73		4.23		34.26		66.00		91.86
2025		76.88		4.31		35.54		67.74		94.67
2026		79.08		4.41		36.73		69.31		96.73
Thereafter(1)

AIF 2016 Page 46

	Asia Pacific
	China				Indonesia
	Daqing Crude Oil (U.S. $/bbl)		Natural Gas (U.S. $/mcf)(2)		Natural Gas (U.S. $/mcf)(2)		Inflation rates(3)		Exchange rates(4)
Historical
2016		40.86		10.25		N/A		—		0.76
Forecast
2017		52.00		10.28		6.59		—		0.76
2018		57.82		10.46		6.78		2.00		0.79
2019		62.31		11.14		6.93		2.00		0.82
2020		66.26		12.05		7.07		2.00		0.83
2021		70.25		11.77		7.23		2.00		0.85
2022		72.15		10.33		7.41		2.00		0.85
2023		74.05		10.33		7.52		2.00		0.85
2024		76.00		10.33		7.63		2.00		0.85
2025		77.99		10.33		7.71		2.00		0.85
2026		80.20		10.33		7.70		2.00		0.85
Thereafter(1)

⁽¹⁾ Prices thereafter are escalated at 2 percent per annum except for sales pursuant to GSAs where prices are escalated as per contract.

⁽²⁾  Natural gas prices in China and Indonesia have been updated from the prior year values due to negotiations with the purchasers and are the weighted average based on the various GSAs.

⁽³⁾  Inflation rates represent a percentage for forecasting costs.

⁽⁴⁾  Exchange rate used to generate the benchmark reference prices are quoted in U.S. dollar to Canadian dollar.

AIF 2016 Page 47

Reconciliation of Gross Proved Reserves

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conven- tional Natural Gas (bcf)			Coal Bed Methane (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Canada - Western Canada
End of 2015		65.9			112.6			625.0			803.4			1,721.1			11.9			50.9			1,143.2
Technical Revisions		3.8			14.6			45.7			64.1			38.1			1.8			(1.6	)		69.1
Economic Factors		(0.4	)		(1.9	)		(0.2	)		(2.5	)		(10.5	)		—			(0.3	)		(4.5	)
Acquisitions		0.1			—			3.0			3.1			8.4			—			0.1			4.6
Dispositions		(27.2	)		(44.3	)		—			(71.5	)		(91.3	)		(13.7	)		(1.3	)		(90.4	)
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			2.1			10.3			12.3			13.1			—			0.1			14.7
Production		(8.6	)		(19.8	)		(35.6	)		(64.0	)		(161.9	)		—			(2.9	)		(93.9	)
End of 2016		33.5			63.3			648.1			744.9			1,516.9			—			45.1			1,042.8
Canada - Atlantic Region
End of 2015		55.3			—			—			55.3			—			—			—			55.3
Technical Revisions		4.3			—			—			4.3			—			—			—			4.3
Economic Factors		—			—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		(12.1	)		—			—			(12.1	)		—			—			—			(12.1	)
End of 2016		47.5			—			—			47.5			—			—			—			47.5
China
End of 2015		3.8			—			—			3.8			339.4			—			13.3			73.7
Technical Revisions		0.6			—			—			0.6			102.1			—			2.5			20.1
Economic Factors		—			—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		(2.4	)		—			—			(2.4	)		(41.5	)		—			(2.2	)		(11.5	)
End of 2016		2.0			—			—			2.0			399.9			—			13.6			82.3
Indonesia
End of 2015		—			—			—			—			268.2			—			7.2			51.9
Technical Revisions		—			—			—			—			—			—			—			—
Economic Factors		—			—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—			—
End of 2016		—			—			—			—			268.2			—			7.2			51.9

AIF 2016 Page 48

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conven- tional Natural Gas (bcf)			Coal Bed Methane (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Libya
End of 2015		0.01			—			—			0.01			—			—			—			0.01
Technical Revisions		0.00			—			—			0.00			—			—			—			0.00
Economic Factors		—			—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		(0.01	)		—			—			(0.01	)		—			—			—			(0.01	)
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—			—
End of 2016		—			—			—			—			—			—			—			—
Total
End of 2015		124.9			112.6			625.0			862.5			2,328.7			11.9			71.5			1,324.0
Technical Revisions		8.7			14.6			45.7			69.0			140.1			1.8			0.9			93.5
Economic Factors		(0.4	)		(1.9	)		(0.2	)		(2.5	)		(10.5	)		—			(0.3	)		(4.5	)
Acquisitions		0.1			—			3.0			3.1			8.4			—			0.1			4.6
Dispositions		(27.3	)		(44.3	)		—			(71.5	)		(91.3	)		(13.7	)		(1.3	)		(90.4	)
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			2.1			10.3			12.3			13.1			—			0.1			14.7
Production		(23.1	)		(19.8	)		(35.6	)		(78.5	)		(203.5	)		—			(5.1	)		(117.6	)
End of 2016		83.0			63.3			648.1			794.4			2,185.0			—			65.9			1,224.4

At December 31, 2016, the Company’s proved oil and gas reserves were 1,224 mmboe, down from 1,324 mmboe at the end of 2015. The Company’s 2016 reserve replacement ratio, defined as net additions divided by total production during the period, was 19 percent excluding economic revisions (15 percent including economic revisions). Major changes to proved reserves in 2016 included:

• Disposition of 90 mmboe in the Plains area. The total acquisitions were 5 mmboe, mainly in the Heavy Oil and Gas thermal bitumen area and Western Canada gas plays;

• 47 mmbbls were added as technical revisions to the Heavy Oil and Gas thermal bitumen projects;

• An additional 102 bcf of conventional natural gas were added in proved developed producing reserves for Liwan 3-1 as technical revisions; and

• Additional future drilling locations at Tucker added extensions of 9 mmbbls of bitumen in proved undeveloped reserves.

AIF 2016 Page 49

Reconciliation of Gross Probable Reserves

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conven- tional Natural Gas (bcf)			Coal Bed Methane (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Canada - Western Canada
End of 2015		13.7			34.3			1,279.9			1,327.9			476.9			0.7			11.8			1,419.3
Technical Revisions		(0.6	)		(7.4	)		29.4			21.4			(25.2	)		2.1			(3.2	)		14.4
Economic Factors		—			(0.1	)		0.1			0.1			(3.7	)		—			—			(0.6	)
Revisions - Transfer to Proved		—			(0.8	)		(44.5	)		(45.3	)		(5.8	)		—			(0.1	)		(46.3	)
Acquisitions		—			—			8.0			8.0			0.1			—			—			8.0
Dispositions		(5.1	)		(6.5	)		—			(11.6	)		(19.7	)		(2.8	)		(0.3	)		(15.7	)
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			0.5			1.7			2.3			0.5			—			—			2.3
Production		—			—						—			—			—			—			—
End of 2016		8.2			20.1			1,274.6			1,302.8			423.1			—			8.2			1,381.5
Canada - Atlantic Region
End of 2015		113.7			—			—			113.7			—			—			—			113.7
Technical Revisions		(1.1	)		—			—			(1.1	)		—			—			—			(1.1	)
Economic Factors		—			—			—			—			—			—			—			—
Revisions - Transfer to Proved		(0.7	)		—			—			(0.7	)		—			—			—			(0.7	)
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		47.8			—			—			47.8			—			—			—			47.8
Production		—			—			—			—			—			—			—			—
End of 2016		159.7			—			—			159.7			—			—			—			159.7
China
End of 2015		0.2			—			—			0.2			190.1			—			6.2			38.2
Technical Revisions		(0.2	)		—			—			(0.2	)		—			—			—			(0.3	)
Economic Factors		—			—			—			—			—			—			—			—
Revisions - Transfer to Proved		—			—			—			—			(72.1	)		—			(1.9	)		(13.9	)
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—			—
End of 2016		—			—			—			—			118.0			—			4.3			24.0
Indonesia
End of 2015		—			—			—			—			91.5			—			1.7			16.9
Technical Revisions		—			—			—			—			—			—			—			—
Economic Factors		—			—			—			—			—			—			—			—
Revisions - Transfer to Proved		—			—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			48.1			—			0.4			8.4
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—			—
End of 2016		—			—			—			—			139.6			—			2.1			25.3

AIF 2016 Page 50

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conven- tional Natural Gas (bcf)			Coal Bed Methane (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Libya
End of 2015		—			—			—			—			—			—			—			—
Technical Revisions		—			—			—			—			—			—			—			—
Economic Factors		—			—			—			—			—			—			—			—
Revisions - Transfer to Proved		—			—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—			—
End of 2016		—			—			—			—			—			—			—			—
Total
End of 2015		127.7			34.3			1,279.9			1,441.9			758.5			0.7			19.7			1,588.1
Technical Revisions		(1.9	)		(7.4	)		29.4			20.1			(25.2	)		2.1			(3.2	)		13.1
Economic Factors		—			(0.1	)		0.1			0.1			(3.7	)		—			—			(0.6	)
Revisions - Transfer to Proved		(0.7	)		(0.8	)		(44.5	)		(46.0	)		(77.9	)		—			(2.0	)		(61.0	)
Acquisitions		—			—			8.0			8.0			0.1			—			—			8.0
Dispositions		(5.1	)		(6.5	)		—			(11.6	)		(19.7	)		(2.8	)		(0.3	)		(15.7	)
Discoveries		—			—			—			—			48.1			—			0.4			8.4
Extensions & Improved Recovery		47.8			0.5			1.7			50.0			0.5			—			—			50.1
Production		—			—			—			—			—			—			—			—
End of 2016		167.9			20.1			1,274.6			1,462.5			680.6			—			14.5			1,590.5

Major changes to probable reserves in 2016 included:

• Disposition of 16 mmboe in the Plains area. Total acquisitions were 8 mmboe in the Heavy Oil and Gas business unit thermal bitumen area;

• 29 mmbbls in the Heavy Oil and Gas thermal bitumen projects (3 mmbbls Tucker) were added as technical revisions and an additional 45 mmbbls (9 mmbbls Tucker) were transferred to proved reserves;

• Extensions and improved recovery as a result of adding additional development locations in Atlantic Region added 48 mmbbls of light and medium oil;

• Negative technical revisions to conventional natural gas of 25 bcf were primarily a result of a change in development plans in Western Canada;

• In China 72 bcf of conventional natural gas were transferred to proved reserves; and

• Discoveries of 48 bcf of conventional natural gas are a result of receiving government approval for the Plan of Development for a new field in Indonesia.

AIF 2016 Page 51

Reconciliation of Gross Proved Plus Probable Reserves

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conven- tional Natural Gas (bcf)			Coal Bed Methane (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Canada - Western Canada
End of 2015		79.6			146.9			1,904.8			2,131.3			2,198.0			12.5			62.7			2,562.5
Technical Revisions		3.2			7.2			75.1			85.5			12.9			3.9			(4.8	)		83.5
Economic Factors		(0.3	)		(2.0	)		(0.1	)		(2.4	)		(14.2	)		—			(0.3	)		(5.1	)
Revisions - Transfer to Proved		—			(0.8	)		(44.5	)		(45.3	)		(5.8	)		—			(0.1	)		(46.3	)
Acquisitions		0.1			—			11.0			11.1			8.5			—			0.1			12.7
Dispositions		(32.3	)		(50.8	)		—			(83.1	)		(111.0	)		(16.4	)		(1.7	)		(106.1	)
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			2.6			12.0			14.6			13.6			—			0.1			17.0
Production		(8.6	)		(19.8	)		(35.6	)		(64.0	)		(161.9	)		—			(2.9	)		(93.9	)
End of 2016		41.7			83.3			1,922.7			2,047.7			1,939.9			—			53.3			2,424.3
Canada - Atlantic Region
End of 2015		169.0			—			—			169.0			—			—			—			169.0
Technical Revisions		3.2			—			—			3.2			—			—			—			3.2
Economic Factors		—			—			—			—			—			—			—			—
Revisions - Transfer to Proved		(0.7	)		—			—			(0.7	)		—			—			—			(0.7	)
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		47.8			—			—			47.8			—			—			—			47.8
Production		(12.1	)		—			—			(12.1	)		—			—			—			(12.1	)
End of 2016		207.2			—			—			207.2			—			—			—			207.2
China
End of 2015		4.0			—			—			4.0			529.5			—			19.6			111.8
Technical Revisions		0.4			—			—			0.4			102.1			—			2.5			19.9
Economic Factors		—			—			—			—			—			—			—			—
Revisions - Transfer to Proved		—			—			—			—			(72.1	)		—			(1.9	)		(13.9	)
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		(2.4	)		—			—			(2.4	)		(41.5	)		—			(2.2	)		(11.5	)
End of 2016		2.0			—			—			2.0			517.9			—			17.9			106.3
Indonesia
End of 2015		—			—			—			—			359.7			—			8.8			68.8
Technical Revisions		—			—			—			—			—			—			—			—
Economic Factors		—			—			—			—			—			—			—			—
Revisions - Transfer to Proved		—			—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—			—
Discoveries		—			—			—			—			48.1			—			0.4			8.4
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—			—
End of 2016		—			—			—			—			407.8			—			9.2			77.2

AIF 2016 Page 52

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conven- tional Natural Gas (bcf)			Coal Bed Methane (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Libya
End of 2015		0.01			—			—			0.01			—			—			—			0.01
Technical Revisions		0.00			—			—			0.00			—			—			—			0.00
Economic Factors		—			—			—			—			—			—			—			—
Revisions - Transfer to Proved		—			—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—			—
Dispositions		(0.01	)		—			—			(0.01	)		—			—			—			(0.01	)
Discoveries		—			—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—			—
End of 2016		—			—			—			—			—			—			—			—
Total
End of 2015		252.6			146.9			1,904.8			2,304.4			3,087.2			12.5			91.1			2,912.1
Technical Revisions		6.8			7.2			75.1			89.1			115.0			3.9			(2.3	)		106.6
Economic Factors		(0.3	)		(2.0	)		(0.1	)		(2.4	)		(14.2	)		—			(0.3	)		(5.1	)
Revisions - Transfer to Proved		(0.7	)		(0.8	)		(44.5	)		(46.0	)		(77.9	)		—			(2.0	)		(61.0	)
Acquisitions		0.1			—			11.0			11.1			8.5			—			0.1			12.7
Dispositions		(32.3	)		(50.8	)		—			(83.1	)		(111.0	)		(16.4	)		(1.7	)		(106.1	)
Discoveries		—			—			—			—			48.1			—			0.4			8.4
Extensions & Improved Recovery		47.8			2.6			12.0			62.4			13.6			—			0.1			64.8
Production		(23.1	)		(19.8	)		(35.6	)		(78.5	)		(203.5	)		—			(5.1	)		(117.6	)
End of 2016		250.9			83.3			1,922.7			2,256.9			2,865.7			—			80.4			2,814.9

AIF 2016 Page 53

Undeveloped Reserves

Undeveloped reserves are attributed internally in accordance with standards and procedures contained in the COGEH. Proved undeveloped oil and gas reserves are those reserves that can be estimated with a high degree of certainty to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Probable undeveloped oil and gas reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. Classifications of reserves as proved or probable are only attempts to define the degree of uncertainty associated with the estimates. In addition, whereas proved reserves are those reserves that can be estimated with a high degree of certainty to be economically producible, probable reserves are those reserves that are as likely as not to be recovered. Therefore, probable reserves estimates, by definition, have a higher degree of uncertainty than proved reserves.

Approximately 58 percent of Husky’s gross proved undeveloped reserves are assigned to the Sunrise Energy Project. Production from Phase I of the project started in March 2015, and wells will be drilled in the future to keep the plant full. Approximately 28 percent of Husky’s gross proved undeveloped reserves are assigned to 9 heavy oil projects in the Lloydminster area that are classified as bitumen. Approximately 10 percent of Husky’s gross proved undeveloped reserves are assigned to the liquids-rich Ansell area, and approximately three percent of Husky’s gross proved undeveloped reserves are assigned to the Madura area, a reduction from last year’s nine percent with the transfer of reserves in the BD pool to proved developed as the project nears start-up.

Husky funds capital programs by cash generated from operating activities, cash on hand, equity issuances and short-term and long-term debt. Decisions on the priority of developing the various proved undeveloped and probable undeveloped reserves are based on various factors including economic conditions, technical performance, facility capacity, commercial considerations and size of the development program. The development opportunities are pursued at a pace dependent on capital availability and its allocation, but Husky generally seeks, in accordance with its business plan, to develop its proved and probable undeveloped conventional reserves over five and seven year time periods, respectively. As at December 31, 2016, there were no material proved undeveloped conventional reserves that have remained undeveloped for greater than five years, except for the Company’s thermal bitumen reserves. The proved undeveloped thermal bitumen reserves are scheduled to be developed over the next one to 40 years to fully utilize the steam plant and processing capacity over the life of the current facilities. The probable undeveloped bitumen reserves are scheduled to be developed over the next 40 years which include facility debottlenecks, expansions and additions.

AIF 2016 Page 54

Proved Undeveloped Reserves⁽¹⁾

	Light & Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)				Total Oil (mmbbls)
	First Attributed		Total at year-end		First Attributed		Total at year-end		First Attributed		Total at year-end		First Attributed		Total at year-end
2014		2.3		27.8		8.9		16.7		70.8		299.0		82.0		343.5
2015		4.5		10.4		0.1		5.0		180.7		467.8		185.3		483.2
2016		—		5.7		—		0.3		9.1		488.3		9.1		494.3

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	First Attributed		Total at year-end		First Attributed		Total at year-end		First Attributed		Total at year-end
2014		104.0		648.7		5.6		20.6		104.9		472.2
2015		172.5		611.7		0.7		10.4		214.8		595.6
2016		1.6		435.2		—		3.2		9.4		570.0

⁽¹⁾ Prior year product types have been updated in accordance with the 2015 amendments to NI 51-101 F1.

Probable Undeveloped Reserves⁽¹⁾

	Light & Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)				Total Oil (mmbbls)
	First Attributed		Total at year-end		First Attributed		Total at year-end		First Attributed		Total at year-end		First Attributed		Total at year-end
2014		54.5		128.6		7.6		28.8		41.5		1,468.1		103.6		1,625.5
2015		—		106.4		—		4.9		0.1		1,235.2		0.1		1,346.6
2016		47.8		133.7		—		0.1		1.3		1,234.0		49.1		1,367.7

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	First Attributed		Total at year-end		First Attributed		Total at year-end		First Attributed		Total at year-end
2014		71.6		429.5		3.2		12.7		118.7		1,709.7
2015		143.0		405.4		1.8		8.0		25.7		1,422.2
2016		48.1		345.4		0.4		3.4		57.5		1,428.7

⁽¹⁾  Prior year product types have been updated in accordance with the 2015 amendments to NI 51-101 F1.

AIF 2016 Page 55

Significant Factors or Uncertainties Affecting Reserves Data

Husky’s reserves can be affected significantly by material fluctuations in product pricing, development plans and capital expenditures, operating costs, regulatory changes that impact costs and/or royalties, and production performance. Actual product prices may vary significantly from the forecast price assumptions used by the Company to estimate its reserves, altering the allocation and level of capital expenditures, and accelerating or delaying project schedules. As new information is obtained, the above factors that affect costs, royalties and production performance are reviewed and updated accordingly, which may result in positive or negative revisions to reserves. For additional information on risk factors please see “Risk Factors - Reserves Data and Future Net Revenue Estimates”.

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 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.

Future Development Costs

The Company expects to fund its future development costs by cash generated from operating activities, cash on hand, and short and long-term debt. In addition, the Company has access to additional funding through credit facilities and the issuance of equity through shelf prospectuses, subject to market conditions. The cost associated with this funding would not affect reserves and would not be material in comparison with future net revenues.

The following table includes estimates of the forecasted costs of developing the Company’s proved and proved plus probable reserves as at December 31, 2016:

	Canada				China				Indonesia				Total
Year	Proved Reserves ($ millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($ millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($ millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($ millions)		Proved Plus Probable Reserves ($ millions)
2017		735		1,001		42		42		113		179		890		1,222
2018		467		1,317		4		4		—		40		471		1,362
2019		422		1,462		—		—		—		—		422		1,462
2020		395		960		—		—		—		—		395		960
2021		431		973		—		—		—		—		431		973
Remaining		4,284		19,463		—		—		—		—		4,284		19,463
Total		6,734		25,175		46		46		113		220		6,892		25,440

Abandonment and reclamation costs are not included in the above amounts, but they were included in prior years’ disclosures.

AIF 2016 Page 56

Production Estimates

Yearly Production Estimates for 2017

	Light & Medium Crude Oil (mbbls/day)		Heavy Crude Oil (mbbls/day)		Bitumen (mbbls/day)		Total Oil (mbbls/day)		Conventional Natural Gas (mmcf/day)		Natural Gas Liquids (mbbls/day)		Total (mboe/day)
Canada
Total Gross Proved		46.9		38.9		121.5		207.3		348.9		7.9		273.4
Total Gross Probable		7.5		3.5		6.2		17.2		20.4		0.3		20.9
Total Gross Proved Plus Probable		54.4		42.4		127.8		224.5		369.4		8.2		294.3
China
Total Gross Proved		5.4		—		—		5.4		162.1		6.8		39.3
Total Gross Probable		—		—		—		—		—		0.4		0.4
Total Gross Proved Plus Probable		5.4		—		—		5.4		162.1		7.2		39.6
Indonesia
Total Gross Proved		—		—		—		—		24.9		1.2		5.3
Total Gross Probable		—		—		—		—		7.6		—		1.3
Total Gross Proved Plus Probable		—		—		—		—		32.4		1.2		6.6
Total
Total Gross Proved		52.4		38.9		121.5		212.8		536.0		15.9		318.0
Total Gross Probable		7.5		3.5		6.2		17.2		28.0		0.7		22.6
Total Gross Proved Plus Probable		59.8		42.4		127.8		230.0		563.9		16.6		340.5

No individual property accounts for 20 percent or more of the estimated production disclosed.

AIF 2016 Page 57

Infrastructure and Marketing

The Company is engaged in the marketing of both its own and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke production. The Infrastructure and Marketing business manages the sale and transportation of the Company’s Upstream and Downstream production and third-party commodity trading volumes through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. The Company is able to capture differences between the two markets by utilizing infrastructure capacity to deliver feedstock acquired in Canada to the U.S. market.

Husky Operated Infrastructure

Husky has been involved in the gathering, transporting and storage of heavy crude oil in the Lloydminster area since the early 1960s. Historically, Husky owned and operated the Cold Lake Gathering System and the Saskatchewan Gathering System. The Lloydminster Terminal, with a total storage capacity of 1.0 mmbbls, serves as a hub for the gathering systems. The pipeline systems transport blended heavy crude oil to Lloydminster, accessing markets through Husky’s Upgrader and Asphalt Refinery in Lloydminster. Blended heavy crude oil from the field and synthetic crude oil from the upgrading operations are transported south to Hardisty, Alberta to a connection with the major export trunk pipelines. The Hardisty Terminal, with a total storage capacity of 3.1 mmbbls, acts as the exclusive blending hub for Western Canada Select (“WCS”), the largest heavy oil benchmark pricing point in North America. The blended crude oil is transported to eastern and southern markets on these pipelines.

During 2016, the Company completed the sale of 65 percent of its ownership interest in select midstream assets discussed above 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, HMLP, of which the Company owns 35 percent, PAH owns 48.75 percent and CKI owns 16.25 percent. The Company will remain the operator of the assets.

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.

In 2017, HMLP expects to actively expand the gathering system network and Hardisty terminal to support production growth in the area and further compliment the Company’s heavy oil and bitumen production. The assets will continue to play an integral and valuable role in the successful transportation of heavy oil and bitumen production to end markets by providing connections to the Husky Upgrader or Asphalt Refinery, third party terminals and pipelines through strategic hubs such as the Hardisty Terminal.

Third Party Pipeline Commitments

In 2010, the Company commenced its pipeline commitment on the Keystone pipeline system, which ships Canadian crude oil from Hardisty, Alberta to Patoka, Illinois. This commitment was part of a strategy, commenced in 2006, to expand the market for the Company’s crude oil into the Midwest U.S. This strategy was further supported through the acquisition of the Lima Refinery in 2007, which now enables the Company’s Canadian synthetic and heavy crude oil production along with additional third-party purchases to be processed at the refinery. The Company has the ability to utilize the portion of the Keystone pipeline system that continues to Cushing, Oklahoma, and the Company holds long term firm capacity on the Enbridge Flanagan South pipeline and Southern Access Extension pipeline which connect Enbridge’s Mainline to the U.S. Gulf Coast and Patoka markets.    

Due to the Company’s ongoing Keystone pipeline commitment, the Lima Refinery has the option to access a significant amount of Canadian crude oil as part of its crude feedstock requirements. The Keystone pipeline has also enabled the Company to sell heavy crude oil through interconnecting pipeline systems to the Lima Refinery and into Cushing, Oklahoma.

Since 2012, the pipeline systems leaving Canada have at times been subject to significant apportionment, affecting both Canadian export volumes and crude oil prices in Western Canada. The Company has to a large extent been insulated from these effects through the reliability of its proprietary pipeline system, its firm capacity on export pipelines and the Company’s demand for Canadian crude oil feedstock for its upgrading and refining assets. To date, the Company has been able to avoid any production shut-ins. As a seller and buyer of crude oils, the Company has a relatively balanced exposure to many location and grade differentials.

AIF 2016 Page 58

The Company has been carefully monitoring opportunities to participate in growing crude oil markets accessed by rail, which have developed due to refiners’ desire for inland crude oil which has at times been priced at significant discounts to ocean imports. The Company has made crude oil deliveries to rail loading facilities via trucks where netbacks can be increased relative to pipeline alternatives. While the Company’s primary focus is on low cost pipeline transportation options, the Company has developed the capability to employ rail transport to a variety of crude oil markets.

Natural Gas Storage Facilities

The Company has operated a 25 bcf natural gas storage facility at Hussar, Alberta since 2000. Results from the natural gas storage business are included in Upstream Infrastructure and Marketing.

Commodity Marketing

The Company is a marketer of both its own and third-party production of crude oil, synthetic crude oil, NGL, natural gas and sulphur. The Company also markets petroleum coke, a by-product from the Lloydminster Upgrader and its Ohio refineries. The Company supplies feedstock to its Lloydminster Upgrader and Asphalt Refinery from its own and third-party heavy oil and bitumen production sourced from the Lloydminster and Cold Lake areas. The Company also sells blended heavy crude oil directly to refiners based in the U.S. and Canada. The extensive infrastructure in the Lloydminster area supports the Company’s heavy crude oil refining and marketing operations.

The Company markets light and medium crude oil and NGLs sourced from the Company’s own production and third-party production. Light crude oil is acquired for processing by the Company’s refinery at Prince George, British Columbia and at Lima, Ohio. The Company markets the synthetic crude oil produced at its Upgrader in Lloydminster to refiners in Canada and the U.S., including the Lima Refinery and other refineries in the Midwest U.S.

The Company markets natural gas sourced from its own production and third-party production. The Company is currently committed to gas sales contracts with third parties, which in aggregate do not exceed amounts forecasted to be deliverable from the Company’s reserves. The natural gas sales contracts are primarily at market prices other than those that meet the Company’s own use requirements. The Company trades natural gas to generate revenue from assets managed, including transportation and natural gas storage facilities.

AIF 2016 Page 59

The Company has developed its commodity marketing operations to include the acquisition of third-party volumes to enhance the value of its midstream assets. Results from the Company’s commodity marketing business are included in Upstream Infrastructure and Marketing.

Downstream Operations

U.S. Refining and Marketing

Lima, Ohio Refinery

The Lima Refinery, located in Ohio between Toledo and Dayton, has an atmospheric crude throughput capacity of 165,000 bbls/day and an operating capacity of 140,000 - 165,000 bbls/day on its current crude slate. The Lima Refinery currently processes both light sweet crude oil and a small percentage of heavy crude oil feedstock sourced from the U.S. and Canada. This includes Canadian synthetic crudes, including Husky Synthetic Blend (“HSB”) produced by the Lloydminster Upgrader. The Lima Refinery produces low sulphur gasoline, gasoline blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products. The feedstocks are received via the Mid-Valley and Marathon Pipelines, and the refined products are transported via the Buckeye, Inland, Sunoco Logistics and Teppco pipeline systems and by rail car to primary markets in Ohio, Illinois, Indiana, Pennsylvania and southern Michigan.

During 2016, crude oil feedstock throughput at the Lima Refinery averaged 129 mbbls/day. This throughput was reduced from normal operations due to a major turnaround in the spring of 2016. In addition, the isocracker was not operational at full capacity until the third quarter of 2016 due to the fire incident in the first quarter of 2015. Production in 2016 consisted of gasoline averaging 67 mbbls/day, total distillates averaging 54 mbbls/day and total other products averaging 18 mbbls/day.

The Lima Refinery continues to progress reliability and profitability improvement projects. FEED commenced in the second half of 2013 to revamp existing refinery process units and add new equipment to allow the Refinery to process up to 40,000 bbls/day of Western Canadian heavy crude oil while maintaining the existing capability and flexibility to refine light crude oil. Regulatory approval was granted by the U.S. Environmental Protection Agency (“EPA”). Current heavy crude oil feedstock capability is up to 10,000 bbls/day. The full scope of the project is expected to be completed in 2018.

BP-Husky Toledo, Ohio Refinery

The BP-Husky Toledo Refinery, in which the Company holds a 50 percent interest, has a nameplate capacity of 160,000 bbls/day and an operating capacity of 135,000 - 145,000 bbls/day on its current crude slate. Products include low sulphur gasoline, ultra-low sulphur diesel, aviation fuels, propane and asphalt. The BP-Husky Toledo Refinery is located in one of the highest energy consumption regions in the U.S.

The BP-Husky Toledo Refinery successfully completed a planned turnaround in the third quarter of 2016. A feedstock optimization project, which was designed to improve the Refinery’s ability to process High-TAN crude, was also completed during the turnaround, which has given the Refinery the ability to process 65,000 bbl/day of High-TAN crude. This supports the strategic intent to process bitumen from the Sunrise Energy Project. As of January 1, 2017, the Company has been marketing its share of the joint operation’s refined product.

During the year ended December 31, 2016, the Company’s share of crude oil feedstock throughput averaged 62 mbbls/day, production of gasoline averaged 37 mbbls/day, distillates averaged 18 mbbls/day and other fuel and feedstock averaged 7 mbbls/day. Production volumes were lower than 2015 due to the 71 day turnaround.

Upgrading Operations

The Company owns and operates the Husky Lloydminster Upgrader, a heavy oil upgrading facility located in Lloydminster, Saskatchewan. The Upgrader is designed to process blended heavy crude oil feedstock into high quality, low sulphur synthetic crude oil. Synthetic crude oil is used as refinery feedstock for the production of transportation fuels in Canada and the U.S. In addition, the Upgrader recovers the diluent, which is blended with the heavy crude oil and bitumen prior to pipeline transportation to reduce viscosity and facilitate its movement, and returns it to the field to be reused.

AIF 2016 Page 60

The Upgrader was commissioned in 1992 with an original design capacity of 46 mbbls/day of synthetic crude oil. Current production is considerably higher than the original design rate capacity as a result of throughput modifications and improved reliability. In 2007, the Upgrader commenced production of transportation grade diesel. The Upgrader’s current rated production capacity is 82 mbbls/day of synthetic crude oil, diluents and ultra low sulphur diesel.

Production at the Upgrader averaged 53 mbbls/day of synthetic crude oil, 14 mbbls/day of diluent and 6 mbbls/day of ultra low sulphur diesel in 2016. In addition, the Upgrader also produced, as by-products of its upgrading operations, approximately 331 long tons/day of sulphur and 876 long tons/day of petroleum coke during 2016. These products are sold in Canadian and international markets.

Canadian Refined Products

The Company’s Canadian Refined Products operations include refining of light crude oil, manufacturing of fuel and fuel grade ethanol, manufacturing of asphalt products from heavy crude oil and acquisition by purchase and exchange of refined petroleum products. The Company’s retail distribution network includes the wholesale, commercial and retail marketing of refined petroleum products and provides a platform for non-fuel related convenience product businesses.

Light oil refined products are produced at the Husky refinery at Prince George, British Columbia and are also acquired from third-party refiners and marketed through Husky retail and commercial petroleum outlets and through direct marketing to third-party dealers and end users. Asphalt and residual products are produced at Husky’s Asphalt Refinery at Lloydminster, Alberta and are marketed directly or through the Company’s eight emulsion plants, five of which are also asphalt terminals located throughout Western Canada.

Prince George Refinery

The Company’s light oil refinery in Prince George, British Columbia, provides refined products to the Company and third-party retail outlets in the central and northern regions of the province. Feedstock is delivered to the Refinery by pipeline from northeastern British Columbia. The Prince George Refinery production is equal to approximately 21 percent of the Company’s total refined product supply requirements.

The Refinery produces all grades of unleaded gasoline, seasonal diesel fuels, mixed propane and butane and heavy fuel oil. During 2016, Refinery throughput averaged 9.4 mbbls/day.

Lloydminster Asphalt Refinery

Husky’s Asphalt Refinery in Lloydminster, Alberta processes heavy crude oil into asphalt products used in road construction and maintenance, and industrial asphalt products. The Refinery has a throughput capacity of 29 mbbls/day of heavy crude oil. The Refinery also produces straight run gasoline, bulk distillates and residuals. The straight run gasoline stream is removed and re-circulated into HMLP’s pipeline network as pipeline diluent and the distillate stream is used by the Upgrader to make ultra low sulphur diesel fuel. The bulk distillates are hydrogen deficient and are transferred directly to the Upgrader and then treated for blending into the HSB stream. Residuals are a blend of medium and light distillate and gas oil streams, which are sold directly to customers typically as drilling and well fracturing fluids or used in asphalt cutbacks and emulsions.

Refinery throughput averaged 28 mbbls/day of blended heavy crude oil feedstock during 2016. In 2016, daily sales volumes of asphalt averaged 15 mbbls/day and daily sales volumes of residual and other products averaged 13 mbbls/day. Due to the seasonal demand for asphalt products, most Canadian asphalt refineries typically operate at full capacity only during the normal paving season in Canada and the northern U.S. The Company has implemented various strategies to increase refinery throughput during the other months of the year, such as increasing storage capacity and developing U.S. markets for asphalt products. This allows the Lloydminster Asphalt Refinery to run at or near full capacity throughout the year.

Asphalt Distribution Network

In addition to sales directly from the Lloydminster Asphalt Refinery, the Company has an asphalt distribution network which consists of emulsion plants and asphalt terminals located at Kamloops, British Columbia, Edmonton and Lethbridge, Alberta, Yorkton, Saskatchewan and Winnipeg, Manitoba and two emulsion plants located at Lloydminster and Saskatoon, Saskatchewan. The Company also terminals asphalt at its Prince George Refinery and uses independently operated terminals in British Columbia, Alberta and in Washington State.

AIF 2016 Page 61

The Company’s sales to the U.S. and Eastern Canada accounted for over 50 percent of its total asphalt sales in 2016. Exported asphalt products are shipped as far as California and New York in the U.S. and Nova Scotia in Canada. The Company sold 5.2 mmbbls of asphalt in 2016.

Through the Pounder Emulsions division, the Company has a significant market share in Western Canada for road application emulsion products. Additional non-asphalt based road maintenance products are also marketed and distributed through Pounder Emulsions.

In 2017, the Company plans to increase asphalt modification capacity, expand retail sales in U.S. markets and market residual products as refinery feedstock.

Ethanol Plants

In September 2006, the Company commissioned an ethanol plant in Lloydminster, Saskatchewan. This plant has an annual nameplate capacity of 130 million litres. In December 2007, the Minnedosa, Manitoba ethanol plant was commissioned also with an annual nameplate capacity of 130 million litres and is currently operating above that capacity. In 2016, ethanol production averaged 820,555 litres/day.

The Company’s ethanol production supports its ethanol-blended gasoline marketing program. When added to gasoline, ethanol promotes more complete fuel combustion, prevents fuel line freezing and reduces carbon monoxide emissions, ozone precursors and net emissions of GHG. Environment Canada has designated ethanol blended gasoline as an “Environmental Choice” product. The Company sells a large portion of its production to other major oil companies for their ethanol blending requirements in Western Canada.

During 2012, the Lloydminster plant commissioned a CO₂ capture facility. The plant is currently capturing CO₂ for use in the Company’s non-thermal EOR projects.

Other Supply Arrangements

In addition to the refined petroleum products supplied by the Prince George Refinery of 3.3 mbbls/day and by the Husky Lloydminster Upgrader of 5.3 mbbls/day in 2016, the Company has an exclusive purchase agreement for refined products with Imperial Oil. During 2016, the Company purchased approximately 29.2 mbbls/day of refined petroleum products of which 26.5 mmbls/day were from the exclusive purchase agreement with Imperial Oil. The Company also acquired approximately 9.0 mbbls/day of refined petroleum products pursuant to exchange agreements with third-party refiners in addition to Imperial Oil.

Branded Petroleum Product Outlets and Commercial Distribution

As at December 31, 2016, there were 480 independently operated Husky-branded petroleum product outlets. These outlets include travel centres, convenience stores, cardlock operations and bulk distribution facilities located from the Ontario/Quebec border to the west coast of British Columbia. The Company’s network of travel centres feature a proprietary cardlock system that enables commercial customers to purchase products using a sophisticated card system that processes transactions, provides detailed billing, fuel and sales tax information and offers advanced fraud protection. A variety of full and self-serve retail locations serve urban and rural markets across the network, while the Company’s bulk distributors offer direct sales to commercial and agricultural markets in Western Canada.

During 2015, the Company and Imperial Oil entered into a contractual agreement to create a single expanded truck transport network of approximately 160 sites. The agreement was approved by Canada’s Competition Bureau in June 2016 and contract closing conditions were met late in the fourth quarter 2016. Progress continues to be made on the implementation of the agreement and the consolidation of the two networks is expected in the second half of 2017.

The Company’s retail and commercial operating model is balanced by corporate-owned/lessee-operated and branded dealer owned and operated sites. Retail outlets offer a variety of services, including convenience stores, service bays, 24-hour accessibility, car washes, Husky House restaurants, proprietary and co-branded quick-serve restaurants. In addition to ethanol-blended gasoline, the Company offers diesel, propane and Chevron lubricants to customers. The Company supplies refined petroleum products to its branded independent retailers on an exclusive basis and provides financial and other assistance for location improvements, marketing support and related services.

AIF 2016 Page 62

The following table shows the number of Husky-branded petroleum outlets by province as of December 31, 2016:

	British Columbia		Alberta		Saskatchewan		Manitoba		Ontario		2016 Total		2015 Total
Branded Petroleum Outlets
Retail Owned Outlets		52		62		12		15		72		213		214
Leased		35		34		3		10		29		111		117
Independent Retailers		50		73		10		5		18		156		154
Total		137		169		25		30		119		480		485
Cardlocks (1)		23		30		5		7		19		84		85
Convenience Stores (1)		80		86		14		21		100		301		309
Restaurants		8		10		3		2		13		36		37

⁽¹⁾ Located at branded petroleum outlets.

The Company also markets refined petroleum products directly to various commercial markets, including independent dealers, national rail companies and major industrial and commercial customers in Western Canada and the Northwestern U.S.

The following table shows average daily sales volumes of light refined petroleum products for the periods indicated:

	Years ended December 31,
(mbbls/day)	2016		2015		2014
Gasoline		22.4		23.1		24.8
Diesel fuel		18.5		23.7		24.9
Liquefied Petroleum Gas		0.2		0.2		0.1
		41.1		47.0		49.8

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INDUSTRY OVERVIEW

The operations of the oil and gas industry are governed by a considerable number of laws and regulations mandated by multiple levels of government and regulatory authorities in Canada, the U.S. and other foreign jurisdictions. These laws and regulations, along with global economic conditions, have shaped the developing trends of the industry. The following discussion summarizes the trends, legislation and regulations that the Company believes have the most significant impact on the short and long-term operations of the oil and gas industry.

Crude Oil and Natural Gas Production

The global crude oil supply and demand imbalance persisted during 2016. The increase in global crude oil supply was primarily attributable to growth from U.S. unconventional production and from Organization of Petroleum Exporting Countries (“OPEC”). Total U.S. crude oil production averaged an estimated 8.9 mmbbls/day in 2016, which is lower than the 9.4 mmbbls/day in 2015, but it still represents the second highest level of production since 1985. Crude oil production from OPEC averaged an estimated 39.3 mmbbls/day in 2016 and is expected to decrease to 32.5 mmbbls/day in 2017 as OPEC member countries agreed to reduce production in late 2016.¹

In Canada, production continued to grow from the Western Canadian oil sands. However, growth was at a slower pace than anticipated primarily due to significant declines in benchmark crude oil prices. Further, production was severely affected by the Fort McMurray wildfires in the second quarter of 2016. In the Canadian Association of Petroleum Producers’ (“CAPP”) June 2016 publication, production in Canada was forecasted to increase from 4.0 mmbbls/day in 2015 to 5.5 mmbbls/day by 2030. The majority of production growth in Canada continues to be expected from the oil sands; however the estimates acknowledge the uncertainty that exists surrounding the global price environment.²

Total U.S. natural gas production decreased by approximately 4.8 percent in 2016 compared to 2015 as U.S. natural gas production reached a peak of 75 bcf/day in April 2015. Total Canadian natural gas production was impacted by high natural gas storage inventories due to a relatively warm winter in early 2016 and the Fort McMurray wildfires in May 2016.³

⁽¹⁾  “Short-Term Energy Outlook”, January 2017, U.S. Energy Information Administration

⁽²⁾ “Crude Oil Forecast, Markets and Pipelines”, June 2016, Canadian Association of Petroleum Producers

⁽³⁾ “Market Snapshot: Natural gas markets experience significant highs and lows in 2016”, January 4, 2017, National Energy Board

Commodity Pricing

Crude oil and natural gas producers negotiate purchase and sale contracts directly with respective buyers and these contracts are typically based on the prevailing market price of the commodity. The market price for crude oil is determined largely by global factors and the contract price considers oil quality, transportation and other terms of the agreement. The price for natural gas in Canada is determined primarily by North America fundamentals because virtually all natural gas production in North America is consumed by North American customers, predominantly in the U.S. Commodity prices are based on supply and demand which may fluctuate due to market uncertainty and other factors beyond the control of entities operating in the industry.

The imbalance between global crude oil supply and demand, led primarily by the growth from U.S. unconventional and OPEC production, lower economic growth forecasts from emerging markets and corresponding growth in global crude oil inventories, resulted in the continued weakness of key crude oil benchmarks. However, in late 2016, OPEC came to an agreement to reduce production by 1.2 mmbbls/day from their daily production, which has led to crude oil benchmarks showing signs of recovery. The price of West Texas Intermediate (“WTI”) averaged U.S. $43.32/bbl in 2016 compared to U.S. $48.80/bbl in 2015, and the price of Brent averaged U.S. $43.69/bbl in 2016 compared to U.S. $52.46/bbl 2015.

Market Access

In order to accommodate the growing production of crude oil from Western Canada, the oil and gas industry continues to work with stakeholders to develop a strong network of transportation infrastructure for crude oil, including pipelines, rail, marine and trucks. The development of a strong infrastructure network continues to be an important challenge for the industry in order to obtain market access for the growing supply from Western Canada.¹

⁽¹⁾ “Crude Oil Forecast, Markets and Pipelines”, June 2016, Canadian Association of Petroleum Producers

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Current pipeline capacity for crude oil exiting Western Canada totals 4.0 mmbbls/day. Several proposals have been announced that could increase current capacity by approximately 3.4 mmbbls/day during the next five years; however the in-service dates for many of the pipeline projects have already been delayed or could be further delayed due to extended regulatory processes and/or regulatory and policy changes¹. The proposed pipeline projects, which are subject to various uncertainties, include the Keystone XL to the U.S. Gulf Coast, the Trans Mountain Expansion to Burnaby, British Columbia, the Enbridge Northern Gateway to Kitimat, British Columbia, the TransCanada Energy East to the east coast of Canada and the restoration of Enbridge’s Line 3. In late 2016, the government of Canada granted approval for the Trans Mountain Expansion; the expansion is expected to commence construction in late 2017 and expected to go into service in late 2019.

Royalties, Incentives and Income Taxes

Canada

The amount of royalties payable on production from privately owned lands is negotiated between the mineral freehold owner and the lessee, and this production may also be subject to certain provincial taxes and royalties. Royalty rates for production from Crown lands are determined by provincial governments. When setting royalty rates, commodity prices, levels of production and operating and capital costs are considered. Royalties payable are generally calculated as a percentage of the value of gross production and generally depend on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, depth of well and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the owner’s working interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

Royalty rates pertaining to Husky operations in Western Canada averaged seven percent of gross revenue in 2016 compared to nine percent in 2015 primarily due to a higher percentage of production from thermal projects, which are at a lower royalty rate, and due to lower commodity prices which affected royalties on a sliding scale of price sensitivity. Royalty rates in the Atlantic Region averaged 15 percent in 2016 compared to 11 percent in 2015 primarily due to lower eligible royalty costs.

In early 2016, the Alberta government adopted the recommendation of its Royalty Review Panel. The new royalty framework preserves the existing royalty structure and rates for oil sands. It also creates a harmonized royalty formula for crude oil, natural gas and liquids that emulates a revenue minus cost system. The royalty changes will take effect in 2017 and only apply to new wells. The current Royalties on existing wells are to remain in place for 10 years.

The Canadian federal corporate income tax rate was 15 percent in 2016 and 2015. Provincial rates ranged between 11 percent and 16 percent in both 2016 and 2015.

Other Jurisdictions

Royalty rates in the Asia Pacific Region averaged six percent in 2016 compared to five percent in 2015.

Operations in the U.S are subject to the U.S. federal tax rate of 35 percent and various state-level taxes. Operations in China are subject to the Chinese tax rate of 25 percent. Operations in Indonesia are subject to tax at a rate of 40 percent as governed by each project’s PSC.

Land Tenure Regulation

In Canada, rights to natural resources are largely owned by the provincial and federal governments. Rights are granted to explore for and produce oil and natural gas subject to shared jurisdiction agreements, ELs, significant discovery and production licenses, leases, permits, and provincial legislation which may include contingencies such as obligations to perform work or make payments.

For international jurisdictions, rights to natural resources are largely owned by national governments that grant rights in forms such as ELs and permits, production licenses and PSCs. Companies in the oil and gas industry are subject to ongoing compliance with the regulatory requirements established by the relevant country for the right to explore, develop and produce petroleum and natural gas in that particular jurisdiction.

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Environmental Regulations

All phases of oil and natural gas operations are subject to environmental regulation pursuant to a variety of federal, provincial, state and local laws and regulations, as well as international conventions (collectively, “environmental regulations”).

Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment, including emissions of GHG. Environmental regulations also require that wells, facilities and other properties associated with Husky’s operations be constructed, operated, maintained, abandoned and reclaimed to the satisfaction of pertinent regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments.

Some of the topics that are or could in the future be subject to new or enhanced environmental regulation include:

• Air and GHG emission regulations and mandatory reductions in jurisdictions where the Company has operations;

• increased restrictions on freshwater licensing;

• enhanced groundwater and surface water monitoring;

• enhanced water discharge criteria;

• calculation and regulation of carbon intensity for transportation fuels;

• fuel reformulation to support reduced transportation emissions;

• managing air pollutants at equipment and facility levels with the general goal of ensuring compliance with increasingly more stringent ambient air quality standards;

• potential for a moratorium on development in areas of particular value to species at risk;

• feedstock and product transportation by rail, pipeline and roadway;

• pipeline integrity management;

• reclamation;

• hydraulic fracturing; and

• land use.

Water

Extensive regulations are imposed on Husky’s operations with the general goal of ensuring surface water and fresh groundwater are protected. Guidelines dictate aspects including:

• well, pipeline, and facility offsets from fresh surface water bodies and domestic water wells;

• drilling fluids, well construction materials, and methods to ensure isolation of fresh groundwater aquifers from resource exploration, extraction, and disposal activities;

• baseline domestic water well testing;

• downhole offsets for completions operations, ensuring isolation from fresh groundwater aquifers, with specific risk mitigation expectations for hydraulic fracturing;

• monitoring of fresh groundwater aquifers and wetlands at major operating facilities;

• monitoring of assets that cross fish bearing streams ensuring passage is unrestricted;

• water discharge criteria for onshore and offshore facilities; and

• fluid transport, handling, and storage.

Water withdrawals, in particular freshwater withdrawals, are regulated in all of the jurisdictions in which Husky has operations with the general goal of ensuring that surface and groundwater supplies are not negatively impacted. Husky has reporting requirements relating to most licenced water withdrawals to support operations. Guidelines dictate water source selection and management. Water withdrawals are further governed by local watershed and/or industry water management plans.

Husky recognizes the importance of water security to the success of its operations and engages in dialogue on proposed regulatory changes, both directly and through industry associations, with the general goal of ensuring the Company’s interests are recognized. Husky believes it is sufficiently prepared to fully comply when new water regulations come into force. Husky has a Corporate Water Standard that mandates Water Risk Assessments and Water Management Plans for its facilities, which include consideration of regulatory risks. Water Risk Assessments consider both known proposed water regulations and possible future regulations (not currently proposed). Husky has realized financial impacts due to regulation changes; proposed and future regulation changes could also have financial impacts. The purpose of the Water Risk Assessments is to identify and mitigate these risks.

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Migratory Birds

Canada’s oil and gas industry may affect migratory birds and bird habitat through land disturbance activities. Industry activities risk contravening the Migratory Bird Convention Act (“MBCA”) and supporting legislation that prohibits the disturbance and destruction of migratory birds, their eggs and/or nests. In 2016, the Environmental Enforcement Act introduced a new fine regime that increased maximum fines up to $6 million, with all subsequent fines doubling, for corporations that are convicted under the MBCA. The Company has improved the stewardship of migratory birds through developed standards and additional training.

Air and Climate Change

The current regulatory environment related to air emissions and climate policy is dynamic. The impacts of emerging policy remain largely uncertain as various jurisdictions define and implement new regulations.

Husky operates in many jurisdictions that regulate or have proposed to regulate air pollutants including GHG emissions. Air regulations include:

• absolute and intensity based emissions limits;

• market based frameworks;

• equipment and/or facility level performance standards; and

• other regulatory measures including low carbon fuel and renewable fuel standards.

In addition to climate policy risk, the industry faces physical risks attributable to a changing climate. Husky operates in some of the harshest environments in the world, including offshore at its Atlantic Region assets. Climate change is expected to increase severe weather conditions including winds, flooding and variable temperatures, which are contributing to the melting of northern ice and increased iceberg activity. The Company has in place a number of policies to protect people, equipment and the environment in the event of extreme weather conditions and adverse ice conditions.

Husky is managing physical risk through engineering for 1:100 year weather events. Husky’s Atlantic Region business unit has a robust ice management program that uses a range of resources, including a dedicated ice surveillance aircraft, and works with government agencies including Environment Canada, the Coast Guard and Canadian Ice Service. Regular ice surveillance flights commence in February each year and continue until the threat of ice has abated. In addition, Atlantic Region operators employ a series of supply and support vessels to actively manage ice and icebergs.

Husky engages in consultations for the design of proposed regulations and supports efforts to harmonize regulations across jurisdictions, both directly with regulators and through industry associations.

International Climate Change Agreements

Canada has submitted a Nationally Determined Contribution to reduce GHG emissions by 30 percent below 2005 levels by 2030 as part of the Paris Agreement at the United Nations Framework Convention on Climate Change Conference of the Parties held in Paris, France in December 2015. The Agreement includes pledges from 195 countries including all major emitters globally to reduce emissions such that temperature increases are limited to “well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5 °C.” There is a commitment to review and increase pledges every five years under the Paris Agreement. Canada approved the Paris Agreement in October 2016.

Canadian Federal Regulations

The Canadian federal government has begun addressing emissions from specific sectors of the economy, including working closely with the U.S. government to establish common North American vehicle emissions standards, as well as performance standards for thermal electricity generation. Canada has adopted renewable fuels regulations, requiring fuel producers and importers to have an average of at least five percent of their gasoline supply come from renewable sources (such as ethanol) and to have an average of at least two percent of their diesel supply come from renewable sources (such as bio-diesel).

In 2012, the Canadian Council of Ministers of the Environment agreed to implement a new Air Quality Management System (“AQMS”) with the objective to protect human health and the environment through the continuous improvement of air quality in Canada. AQMS includes three main components: Canadian Ambient Air Quality Standards (“CAAQS”), Base-Level Industrial Emissions Requirements (“BLIERs”), and the management of air quality through local air zones and regional airsheds.

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CAAQS are the AQMS driver and “set the bar” for air quality management across the country. New standards for ozone and fine particulate matter for 2015 and 2020 were published in 2013. New CAAQS for SO₂ for 2020 and 2025 were announced in October 2016. Work has also started to develop new CAAQS for nitrogen dioxide (“NO₂”) for 2020 and 2025.

The first tranche of the Multi-Sector Air Pollutants Regulations was published in the Canada Gazette, Part II in June 2016. These Regulations have included three BLIERs developed under AQMS for the cement sector, reciprocating spark-ignited natural gas engines and non-utility boilers and heaters in industrial sectors. Other sectors and pollutants will be added to the Regulations in the future.

The BLIERs pertaining to nitrogen oxide (“NOx”) emissions from boilers and heaters and NOx emissions from reciprocating engines in industrial facilities are applicable to all Canadian Upstream and Downstream oil and gas facilities within Husky with the exception of the Prince George Refinery since a sector-specific Refining BLIER will be developed separately for petroleum refineries. The Boiler & Heater BLIER and Reciprocating Engine BLIER have introduced performance and design standards for both existing and new equipment units.

In October 2016, the Canadian federal government announced its plan for a minimum carbon price in Canada. The plan is to set a national floor price on carbon at $10 per tonne of carbon dioxide equivalent (“CO₂e”) in 2018 and increase it to $50 per tonne of CO₂e by 2022. Provinces have to meet or exceed that floor price either through a direct price on carbon or a cap-and-trade system. The entire Canadian economy will be impacted by this carbon pricing policy and therefore all aspects and levels of government are engaged.

The Federal Government of Canada is committing to reduce methane emissions from the oil and gas sector by 40 to 45 percent below 2012 levels by 2025. To implement this commitment, the federal government is expected to introduce regulations to reduce methane emissions from the oil and gas sector to address venting and fugitive emissions. The Canadian requirements are expected to cover emissions from the same sources that are subject to current and proposed U.S. regulatory requirements and will also require reductions from some unique Canadian sources such as heavy crude oil.

These regulations are expected to apply to new and existing sources, with the first requirements expected to come into force as early as 2020, and the remaining requirements expected to come into force by 2023.

The regulations are expected to apply to oil and gas facilities that are responsible for the extraction, production and processing and transportation of crude oil and natural gas. Regulatory requirements are expected to be designed to cover specific methane emission sources in Canada while minimizing administrative burden and providing the flexibility needed for efficient and effective operations in Canadian circumstances. Covered sources are expected to include: venting from wells and batteries (including associated gas at oil facilities), storage tanks, pneumatic devices, well completions, compressors and fugitive equipment leaks.

Environment and Climate Change Canada is expected to negotiate equivalency agreements with interested provinces and territories to enable these jurisdictions to be front-line regulators where they have legally binding regimes that produce equal or better environmental outcomes.

Canadian Provincial Greenhouse Gas Regulations

In 2015, Alberta announced a major shift in its climate regulations through its Climate Leadership Plan. It includes four key areas in which the Government of Alberta is moving forward:

1. Phasing out emissions from coal-generated electricity and developing more renewable energy

2. Implementing a new carbon price on emissions of GHG

3. A legislated oil sands emission limit

4. Employing a new methane emission reduction plan

Existing regulations provide that, facilities that emit over 100,000 tons of CO₂e per year, large final emitting facilities (“LFEs”), are required to reduce their emissions intensity by 20 percent by January 1, 2017. The price of the carbon levy (which may be used to make up for any shortfall in actual emissions intensity reductions) has increased from $15/tCO₂e to $20/tCO₂e for 2016 and $30/tCO₂e for 2017. As of January 1, 2018, LFEs will fall under a newly proposed carbon competitiveness regulation that will employ output-based allocations to benchmark facilities against peers. Industry and government are in ongoing consultations on the details of this regulation.

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As of January 1, 2017 Alberta will be implementing a broad-based carbon price designed to cover emissions across all sectors, starting at $20 per tonne and moving to $30 per tonne on January 1, 2018. The government has signalled an intention to increase the price in real terms periodically after 2018. Emissions from the combustion of produced fuel at conventional oil and gas facilities emitting less than 100,000 tons of CO₂e per year will be exempt until January 1, 2023, to allow time for these facilities to reduce methane emissions under developing provincial and federal methane regulations. Consultations with industry and other stakeholders are ongoing to develop these regulations. Finally, total emissions from the oil sands will be capped at a maximum of 100 megatons in any year, with provisions for cogeneration and new upgrading capacity. The details of how this emissions limit will be implemented have not been finalized.

The AER is working collaboratively to develop and implement an efficient and effective regulatory framework that achieves the Government of Alberta’s methane emissions reduction outcome of 45 percent by 2025. Alberta intends to reduce methane emissions from oil and gas operations by 45 percent by 2025 using the following approaches:

1. Applying new emissions design standards to new Alberta facilities.

2. Improving measurement and reporting of methane emissions, as well as leak detection and repair requirements.

3. Developing a joint initiative on methane reduction and verification for existing facilities and backstopping this with regulated standards that take effect in 2020, with the general goal of ensuring the 2025 target is met.

Alberta’s reduction target and timeline match the commitments announced by the Canadian and American federal governments and are consistent with the AERs approach of protecting Alberta’s economic competitiveness through alignment with North American environmental standards.

In October 2016, the Government of Saskatchewan released a climate change plan as an alternative approach to the federal government’s announced carbon price. Saskatchewan’s White Paper on Climate Change suggests balancing action on climate change issues by considering three basic approaches:

1. An emphasis on mitigation through emissions reductions: taxation regimes that attempt to change consumer behaviour, cap and trade systems, levies on large emitters, new regulations for the oil and gas sector and new regulations for power producers.

2. An emphasis on adaptation practices and technology: minimizing the impact of future climate events, reducing the vulnerability of provincial infrastructure, protecting community land and water resources, fostering an effective risk assessment and disaster recovery system, a better understanding of the risks associated with more frequent extreme climate events and improving our climate models to better predict the frequency and scale of these events.

3. A focus on innovation and technological development for domestic and international markets.

While looking at all three approaches, the Government of Saskatchewan believes the third option - innovation and technological development - offers the greatest potential for significant improvements in global GHG emissions while causing the least harm to the province’s economy. Also, when the resource economy strengthens, the Government of Saskatchewan will move ahead with plans for a fund supported by a levy on large emitters, with the fund’s expenditures limited to new technologies and innovation to reduce GHG emissions and not for general revenue.

In British Columbia, regulations established in 2008 target a provincial reduction in GHG emissions of at least 33 percent below 2007 levels by 2020 and 80 percent below 2007 levels by 2050. British Columbia’s Greenhouse Gas Industrial Reporting and Control Act will limit emissions from Liquefied Natural Gas (“LNG”) facilities to 0.16 tons of GHG emissions for each 1 ton of LNG processed by the operator once implemented.

British Columbia currently has a $30 per ton carbon tax that is in place on fuel Husky uses and purchases in that jurisdiction, which affects all of the Company’s operations in British Columbia. Additionally, British Columbia has a Renewable and Low Carbon Fuel Requirements Regulation in place that requires a reduction in the allowable carbon intensities of all fuels, with penalties applied for intensities that do not meet targets.

The British Columbia government released its Climate Leadership Plan in August 2016. The 21 actions are targeted across all major sectors of the economy, including annual reductions of up to five million tons CO₂ by 2050 in the oil and gas sector through a focus on methane emissions, carbon capture and storage as well as electrification. The B.C. government has not announced plans to update the provincial price on carbon beyond the current $30/tonne level at this time.

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The Manitoba government released its Climate Change and Green Economy Action Plan in December 2015. Manitoba has pledged to cut GHG emissions from 2005 levels by one-third by 2030 and by one-half by 2050. The province will seek to be carbon-neutral by 2080. In September 2016, Manitoba Sustainable Development held a workshop on Carbon Pricing and Climate Change to explore key environmental and economic policy and design issues associated with carbon pricing, consider implications and trade-offs of each and identify important features for consideration in the province’s approach, including options for revenue recycling, as well as adaptation and mitigation measures.

The Ontario government finalized the rules for its new cap and trade program in May 2016. The cap and trade regulation took effect on July 1, 2016 and included detailed requirements for businesses participating in the program, including: GHG emission caps, entities covered by the program, compliance, auction and sale of allowances and distribution of allowances. The program also regulates end-use combustion of transportation fuels. The Greenhouse Gas Reduction Account will receive proceeds from Ontario’s cap and trade program. Funds from this account will be used for the purpose of reimbursing the Crown for costs incurred in administering the regulations in relation to GHG and for carrying out or supporting GHG reduction initiatives. The first auction is targeted for March 2017. Ontario intends to link its cap and trade program with Québec and California.

On November 9, 2016, the Government of Newfoundland and Labrador released The Way Forward: A Vision for Sustainability and Growth in Newfoundland and Labrador, indicating it is committed to making progress on the issue of climate change. The Newfoundland and Labrador (“NL”) Government is working toward reducing provincial emissions of GHG to ten per cent below 1990 levels, by 2020. The NL Government is following the Federal Government’s Pan-Canadian Approach to Pricing Carbon Pollution released to the first ministers in early October 2016; however the NL Government has yet to determine a specific mechanism to meet the federal mandate for carbon pricing. Jurisdictional issues are also being discussed between the provincial and federal governments as offshore oil and gas facilities operate on federal lands, under the jurisdiction of Offshore Petroleum Boards, and constitutionally are not under provincial jurisdiction.

U.S. Greenhouse Gas Regulations

The U.S. does not have federal legislation establishing targets for the reduction of or limits on the emission of GHGs. However, the federal EPA has and may continue to promulgate regulations concerning the reporting and control of GHG emissions. Since 2010, the EPA’s Greenhouse Gas Reporting Program (“GHGRP”) requires any facility releasing more than 25,000 tons per year of CO₂e emissions to report those emissions on an annual basis. In addition to reporting direct CO₂e emissions, the GHGRP requires refineries to estimate the CO₂e emissions from the potential subsequent combustion of the refinery’s products.

In May 2010, the EPA finalized the Greenhouse Gas Tailoring Rule. This rule “tailored” the Clean Air Act by phasing in permitting requirements for GHG emissions, including Best Available Control Technology (“BACT”) requirements for new and modified sources of air emissions emitting more than a threshold quantity of GHGs. In June 2014, the U.S. Supreme Court issued its opinion in Utility Air Regulatory Group v. EPA. The Court invalidated portions of the Tailoring Rule but upheld the EPA’s authority to require BACT for GHG emissions associated with sources that must obtain Prevention of Significant Deterioration permits based on their non-GHG emissions. Based on the Court’s opinion, it is possible that the EPA will amend the Tailoring Rule in a way that imposes additional GHG requirements on Husky’s U.S. operations.

The EPA has previously issued standards for the oil and gas production and transmission sector that, among other requirements, mandates the use of specified Reduced Emissions Completions (“REC”) for hydraulically fractured natural gas wells. In May 2016, the EPA issued final methane emissions standards for the upstream oil and gas sector, including an extension of REC requirements to hydraulically fractured oil wells.

The EPA has not yet issued proposed or final GHG emissions standards for new or existing refineries but could do so in the future. These and other EPA regulations regarding GHG emissions are subject to judicial challenges and could be modified by regulatory actions or new legislation.

U.S. Renewable Fuel Standard

The U.S. created its renewable fuel standard (“RFS”) program with the stated intention of reducing greenhouse gas emissions and expanding the renewable fuels sector, while reducing U.S. reliance on imported oil. The RFS program was authorized under the Energy Policy Act of 2005 and expanded under the Energy Independence and Security Act of 2007. The U.S. EPA implements the RFS program in consultation with the U.S. Department of Agriculture and Department of Energy.

The RFS program is a national policy that requires a certain volume of renewable fuel to replace or reduce the quantity of pertroleum-based transportation fuel, heating oil or jet fuel. Obligated parties under the RFS program are refiners or importers of gasoline or diesel fuel. Compliance is achieved by blending renewable fuels into transportation fuel or by obtaining credits (called “Renewable Identification Numbers”, or “RINs”) to meet an EPA-specified Renewable Volume Obligation (“RVO”).

The U.S. EPA calculates and establishes RVOs every year through rulemaking. The standards are converted into a percentage, and obligated parties must demonstrate compliance anually.

Pipeline Integrity

Recent high-profile oil spill events have led to a significant increase in exposure and expectation for environmental protection amongst the public, by governments and regulators and within industry.

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Governments are setting new expectations for pipeline integrity management and spill response. The B.C. Government has outlined five minimum requirements that must be met for the province to consider the construction of heavy oil pipelines within its borders. Governments, through their regulators, have increased the number of inspections and reviews and in parallel have put in place a series of new expectations for stronger pipeline integrity and spill management. Saskatchewan introduced legislative amendments to its Pipelines Act in November 2016, including plans to licence flowlines in the province, establishing new inspection, investigation and compliance audit powers, providing requirements for financial assurance from operators for pipelines in high-risk locations such as water crossings and new obligations associated with environmental issues that could occur following pipeline abandonment.

Industry, as a group, has responded by developing and implementing best practice guidelines designed to deliver the new expectations.

On July 21, 2016, subsequent to the formation of HMLP, Husky discovered a leak on the 16TAN pipeline, part of the SGS, where it crosses the North Saskatchewan River. The pipeline was immediately isolated at the river crossing valves and spill response crews were dispatched. Approximately 225 cubic metres (“m³”) (plus or minus 10 percent), was released, with about 40 percent of that volume entering the river. As of December 31, 2016, shoreline cleanup operations accounted for 210 m³. Total gross costs incurred in response to the spill were approximately $107 million, of which $88 million has been recovered through insurance proceeds. Both the spill costs and insurance recoveries have been incurred by HMLP.

An investigation undertaken by Husky and third-party experts concluded the pipeline break was caused by geotechnical activity. The break was a sudden, one-time event in a section of the pipe that had buckled due to the force of ground movement. Regulators are conducting a review of the incident.

While the investigation has concluded the SGS was designed and constructed in accordance with applicable standards and operators responded appropriately, Husky is implementing improvements to systems and operating procedures. A number of actions are being undertaken, including ensuring geotechnical risks are addressed and re-assessed over the life of a pipeline with mitigation and monitoring strategies, consistent with current procedures; applying additional safety loading factors to locations susceptible to potential geotechnical risk; review and consolidation of existing leak detection processes and procedures, including a defined time period for diagnostic analysis before proceeding to mandatory shutdown; and adjusting variables on the leak detection system to reduce the number of false alarms.

Abandonment Liability

Over a three year period, the AER phased in parameter updates to the licencee abandonment liability program. These changes were fully implemented in May 2015 under Directive 006: Licencee Liability Rating Program and Licence Transfer Process and effected important changes to the Licencee Liability Rating Program. The Licencee Liability Rating Program is designed to prevent Alberta taxpayers from incurring costs to suspend, abandon, remediate and reclaim a well, facility or pipeline. Under the Licencee Liability Rating Program, each licencee is assigned a Liability Management Rating. Liability Management Rating is the ratio of a licencee’s eligible deemed assets under the Licencee Liability Rating Program, the Large Facility Liability Management Program and the Oilfield Waste Liability Program to its deemed liabilities in these programs. The Liability Management Rating assessment is designed to assess a licencee’s ability to address its suspension, abandonment, remediation and reclamation liabilities. This assessment is conducted monthly and on receipt of a licence transfer application in which the licencee is the transferor or transferee.

If a licencee’s deemed liabilities exceed its deemed assets, the licencee is required to post a security deposit with the AER to make up the shortfall. If a licencee fails to post security, if required, then the AER may take a number of steps to enforce these provisions, which include non-compliance fees, partial or full suspension of operations, suspension and/or cancellation of a permit, licence or approval and prevention of the transfer of licences held by licencees that do not meet the new requirements.

As a result of the Redwater Energy bankruptcy court ruling, whereby the court found that receivers and trustees of AER licensees may selectively disclaim unprofitable assets (and their associated abandonment and reclamation obligations) under section 14.06 of the federal Bankruptcy and Insolvency Act, the AER and the Orphan Well Association are actively working on appropriate regulatory measures to mitigate the liability impact of licensee’s abandonment, reclamation and remediation obligations from falling back to the industry.

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Consequently, a condition of transferring existing AER licenses, approvals and permits, will require all transferees to demonstrate that they have a liability management ratio (“LMR”) of 2.0 or higher immediately following the transfer. The AER recognizes this is a significant change, but they have observed that purchasers with an LMR of 1.0 or below have had significant difficulty meeting their liabilities after the transfer. If the transfer of the licensee does not improve the purchaser’s LMR to 2.0 (or higher), the purchaser can post a security deposit, address existing abandonment obligations or transfer additional assets.

Similar to the AER, the Government of Saskatchewan has established an LMR rating of 1.0 as their threshold for providing a deposit. If a licensee’s LMR is less than 1.0, meaning the liability is greater than the deemed assets, that licensee will be required to submit a deposit to the Saskatchewan Ministry of the Economy (“ECON”) for the amount of the difference.

In response to the Redwater Energy ruling, all licence transfer applications in Saskatchewan will be reviewed in detail, and ECON will consider all relevant factors in calculating transfer deposit requirements. In addition to increased deposit requirements, ECON may incorporate additional conditions with licence transfer approvals which may impact the decision to proceed with certain transactions.

The Government of Saskatchewan is applying to intervene in the Alberta Court proceedings regarding Redwater’s bankruptcy with the general goal of ensuring their views are fully considered by the courts. The Saskatchewan Ministry of Justice has indicated opposition to any attempt by a receiver in Saskatchewan to renounce uneconomic oil and gas assets which are subject to the LMR program in Saskatchewan. All licence transfer applications in Saskatchewan will now be considered non-routine as the Saskatchewan ministry will not be strictly relying on the standard LMR calculations in evaluating deposit requirements.

Hydraulic Fracturing

Hydraulic fracturing is a method of increasing well production by injecting fluid under high pressure down a well to crack the hydrocarbon bearing rock. In the case of water-based fractures, the fluid typically consists of water, sand, and a relatively small amount of chemicals. This mixture flows into the cracks where the sand remains to keep the cracks open and enable natural gas or liquids to be recovered. Fracturing fluids are produced back to the surface through the wellbore and are stored for reuse or future disposal in accordance with provincial regulations. The wells are designed and installed to provide multiple barriers protecting fresh groundwater aquifers from the fracturing process.

The Government of Canada manages use of chemicals through its Chemical Management Plan and New Substances Program. Some provinces require the details of fracturing fluids to be submitted to regulators. In Alberta, the AER requires that all fracturing operations submit reports regarding the quantity of fluids and additives. For Alberta and British Columbia, the website www.FracFocus.ca provides the public with access to individual well summaries of the fluids and chemicals reported.

In response to concerns that hydraulic fracturing may induce seismic events, the AER has imposed requirements for seismic monitoring, mitigation response plans and reporting in select areas of the province.

Land Use

In 2012, the Government of Alberta approved the Lower Athabasca Regional Plan (“LARP”), which covers the lower Athabasca region and includes Husky’s oil sands assets and major projects in the province. The LARP was developed to consider cumulative effects within the region using formal management frameworks for: Air Quality, Surface Water Quality and Quantity, Groundwater Management and Biodiversity.

The use of each framework establishes approaches with the general goal of ensuring trends are identified and assessed, regional limits are not exceeded and air, water and biodiversity remain healthy for the region’s residents and ecosystems during oil sands development. To date, the Biodiversity Framework under LARP has not been finalized.

Industry Collaboration Initiatives

Husky participates in a number of industry associations and sustainability groups to better understand environmental, safety and social issues while benefitting from and contributing to industry innovation and good management practices.

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Through Husky’s membership in Canada’s upstream industry association, CAPP, and the Canadian Fuels Association (“CFA”) which represents Canada’s transportation fuels industry, the Company enhances its ability to identify and address potential policy and regulatory risks to Husky’s business and participates in advocacy related activity to reduce those risks. Husky participates on the CAPP board of Governors, as well as various Executive Policy Groups and working level groups and committees that focus on areas of policy or regulation that have been identified as areas of interest or impact to Husky’s business.

Husky is a member of IPIECA, the global oil and gas industry association for environmental and social issues, and is participating in its Water Task Force and Climate Change Working Group as well as other topic focused groups. The Company is also a member of Oil Spill Response Limited, an international industry-owned cooperative whose objective is to respond effectively to oil spills wherever in the world they may occur. In 2016, Husky joined the IETA and is participating in its Canadian Working Group. The IETA’s objective is to build international policy and market frameworks for reducing GHG at the lowest cost.

Husky also collaborates on water and carbon management and risk mitigation through involvement in industry initiatives and committees. As a member of the joint-industry Water Technology Development Centre and other joint-industry projects, Husky is committed to developing technologies that will reduce water and energy use for in-situ thermal heavy oil operations.

Husky pursues memberships with the following additional sustainability groups and industry associations:

Alberta Industrial Fire Protection Association, Allen Count Environmental Citizen’s Advisory Committee, American Fuel & Petrochemical Manufacturers, Beaver River Watershed Alliance, Calgary Region Airshed Zone, Canadian Association of Petroleum Producers, Canadian Brownfields Network, Canadian Fuels Association, Canadian Land Reclamation Association, China Offshore Environmental Services, China Offshore Oil Operation Safety Office, China’s State Oceanic Administration, China’s Marine Safety Administration, Clearwater Mutual Aid CO-OP, Clearwater Trails Initiative, Conference Board of Canada - Council on Emergency Management, Cumulative Environmental Management Association, Devonian Aquifer Working Group - Canada’s Oil Sands Innovation Alliance joint industry project, Earth Rangers, Eastern Canada Response Corporation, Edson Mutual Aid Committee, Emergency Response Assistance Canada, Environmental Services Association of Alberta, Environmental Studies Research Funds, Faster Forests (Canada’s Oil Sands Innovation Alliance), Foothills Research Institute - Grizzly Bear Program, Foothills Restoration Forum - Southwest Alberta Sustainable Community Initiative, Grasslands Air Zone, Hardisty Mutual Aid Plan, International Emissions Trading Association, Indonesian Petroleum Association, International Oil & Gas Producers Association, International Petroleum Industry Environmental Conservation Association, Joint Canada-Alberta Plan for Oil Sands Monitoring, Lakeland Industry and Community Association, Land Spill Emergency Program, Lloydminster Emergency Preparedness Stakeholder Group, Mackenzie Delta Spill Response Corporation, Marine Pollution Control, Mutual Aid Alberta, North Saskatchewan Watershed Alliance, Ohio Chemistry Trade Council, Oil Spill Response Limited, One Ocean, Orphan Well Association, Ottawa River Coalition, Parkland Airshed Management Zone, Petroleum Research Newfoundland and Labrador, Petroleum Technology Alliance Canada, Plains CO₂ Reduction Partnership, Prince George Air Improvement Roundtable, Saskatchewan Petroleum Industry Government Environmental Committee, Saskatchewan Prairie Conservation Action Plan , Southeast Saskatchewan Airshed Association, Transportation Community Awareness and Emergency Response, Upstream Saskatchewan Spill Response Co-op Area 2, 3 & 4 Spill Response Cooperatives, Water Technology Development Centre - Canada’s Oil Sands Innovation Alliance joint industry project, Western Canada Marine Response Corporation, Western Canadian Spill Services, Western Yellowhead Air Management Zone and Wood Buffalo Environmental Association.

Husky’s Sustainability Commitment

Husky’s sustainability is a key pillar of the financial well-being of the Company. While sustainability begins with a strong financial foundation, success is directly linked to how the Company conducts its business, whether it is by improving safety, by taking steps to protect the environment or in delivering lasting benefits to the communities. More information can be found in the Husky Energy 2015 Community Report, which can be accessed under both the Social Responsibility and Environment sections of www.huskyenergy.com.

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RISK FACTORS

The following summarizes what Husky believes to be the most significant risks relating to its operations that should be considered when purchasing securities of Husky. Husky has developed an enterprise risk matrix to identify risks to its people, the environment, its assets and its reputation, and to systematically mitigate these risks to an acceptable level. The risk matrix and associated mitigation strategies are reviewed quarterly by senior management and the Audit Committee and annually by the Board of Directors.

Operational, Environmental and Safety Incidents

The Company’s businesses are subject to inherent operational risks in respect to safety and the environment that require continuous vigilance. The Company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner using HOIMS, its integrated management system that considers environmental requirements and process and occupational safety. Failure to manage the risks effectively could result in potential fatalities, serious injury, interruptions to activities or use of assets, damage to assets, environmental impact or loss of licence to operate. Enterprise risk management, emergency preparedness, business continuity and security policies and programs are in place for all operating areas and are adhered to on an ongoing basis. The Company, in accordance with industry practice, maintains insurance coverage against losses from certain of these risks. Nonetheless, insurance proceeds may not be sufficient to cover all losses, and insurance coverage may not be available for all types of operational risks.

Commodity Price Volatility

Husky’s results of operations and financial condition are dependent on the prices received for its refined products, crude oil, NGL and natural gas production. Lower prices for crude oil, NGLs and natural gas could adversely affect the value and quantity of Husky’s oil and gas reserves. Husky’s reserves include significant quantities of heavier grades of crude oil that trade at a discount to light crude oil. Heavier grades of crude oil are typically more expensive to produce, process, transport and refine into high value refined products. Refining and transportation capacity for heavy crude oil is limited and planned increases of North American heavy crude oil production may create the need for additional heavy oil refining and transportation capacity. Wider price differentials between heavier and lighter grades of crude oil could have a material adverse effect on Husky’s results of operations and financial condition, reduce the value and quantities of Husky’s heavier crude oil reserves and delay or cancel projects that involve the development of heavier crude oil resources. There is no guarantee that pipeline development projects will provide sufficient transportation capacity and access to refining capacity to accommodate expected increases in North American heavy crude oil production.

Prices for refined products and crude oil are based on world supply and demand. Supply and demand can be affected by a number of factors including, but not limited to, actions taken by OPEC, non-OPEC crude oil supply, social conditions in oil producing countries, the occurrence of natural disasters, general and specific economic conditions, technological developments, prevailing weather patterns and the availability of alternate sources of energy.

Husky’s natural gas production is currently located in Western Canada and the Asia Pacific Region. Western Canada is subject to North American market forces. North American natural gas supply and demand is affected by a number of factors including, but not limited to, the amount of natural gas available to specific market areas either from the well head of existing or accessible conventional or unconventional sources (such as from shale), or from storage facilities, technological developments, prevailing weather patterns, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions.

The natural gas Husky produces in the Asia Pacific Region is sold to specific buyers with long-term contracts. For the Liwan 3-1 gas field, a price profile has been fixed for five years and then will be linked to local benchmark pricing for the years following subject to a floor and ceiling. For the Liuhua 34-2 field, the price is fixed with a single escalation step during the contract delivery period. Natural gas price in North America is affected primarily by supply and demand, as well as by prices for alternative energy sources.

In certain instances, the Company uses derivative commodity instruments and futures contracts on commodity exchanges, including commodity put and call options under a short-term hedging program, to manage exposure to price volatility on a portion of its refined product, oil and gas production, inventory or volumes in long distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and natural gas.

The fluctuations in refined products, crude oil and natural gas prices are beyond the Company’s control and could have a material adverse effect on the Company’s results of operations and financial condition.

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Reservoir Performance Risk

Lower than projected reservoir performance on the Company’s key growth projects could have a material adverse effect on the Company’s results of operations, financial condition and business strategy. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets and negatively affect the Company’s reputation, investor confidence and the Company’s ability to deliver on its growth strategy.

In order to maintain the Company’s future production of crude oil, natural gas and NGLs and maintain the value of the reserves portfolio, additional reserves must be added through discoveries, extensions, improved recovery, performance related revisions and acquisitions. The production rate of oil and gas properties tends to decline as reserves are depleted while the associated unit operating costs increase. In order to mitigate the effects of this, the Company must undertake successful exploration and development programs, increase the recovery factor from existing properties through applied technology and identify and execute strategic acquisitions of proved developed and undeveloped properties and unproved prospects. Maintaining an inventory of projects that can be developed depends upon, but is not limited to, obtaining and renewing rights to explore, develop and produce oil and natural gas, drilling success, completion of long lead time capital intensive projects on budget and on schedule and the application of successful exploitation techniques on mature properties.

Restricted Market Access and Pipeline Interruptions

Husky’s results depend upon the Company’s ability to deliver products to the most attractive markets. The Company’s results of operations could be materially adversely effected by restricted market access resulting from a lack of pipeline or other transportation alternatives to attractive markets as well as regulatory and/or other marketplace barriers. Interruptions and restrictions may be caused by the inability of a pipeline to operate, or they can be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. With growing oil production across North America and the limited availability of infrastructure to carry the Company’s products to the marketplace, oil and natural gas transportation capacity is expected to be restricted in the next few years. Restricted market access may potentially have a material adverse effect on the Company’s results of operations, financial condition and business strategy. Unplanned shutdowns and closures of its refineries or Upgrader may limit Husky’s ability to deliver product with a material adverse effect on sales and results of operations.

Security and Terrorist Threats

Security threats and terrorist or activist activities may impact the Company’s personnel, which could result in injury, death, extortion, hostage situations and/or kidnapping, including unlawful confinement. A security threat, terrorist attack or activist incident targeted at a facility, office or offshore vessel/installation owned or operated by the Company could result in the interruption or cessation of key elements of the Company’s operations. Outcomes of such incidents could have a material adverse effect on the Company’s results of operations, financial condition and business strategy.

International Operations

International operations can expose the Company to uncertain political, economic and other risks. The Company’s operations in certain jurisdictions may be adversely affected by political, economic or social instability or events. These events may include, but are not limited to, onerous fiscal policy, renegotiation or nullification of agreements and treaties, imposition of onerous regulation, changes in laws governing existing operations, financial constraints, including currency and exchange rate fluctuations, unreasonable taxation and corrupt behaviour of public officials, joint venture partners or third-party representatives that could result in lost business opportunities for Husky. This could materially adversely affect the Company’s interest in its foreign operations, results of operations and financial condition.

Major Project Execution

The Company manages a variety of oil and gas projects ranging from upstream to downstream assets. The risks associated with project development and execution, which include the Company’s ability to obtain the necessary environmental and regulatory approvals, changing government regulation and public expectation in relation to the impact on the environment, as well as the risks involved in commissioning and integration of new assets with existing facilities, can impact the economic feasibility of the Company’s projects. Obtaining regulatory approvals can involve significant stakeholder consultation, environmental impact assessments and public hearings.These risks can result in, among other things, cost overruns, schedule delays and decreases in product markets. These risks can also impact the Company’s safety and environmental performance, which could negatively affect the Company’s reputation.

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Litigation, Administrative Proceedings and Regulatory Actions

The Company may be subject to litigation, claims, administrative proceedings and regulatory actions, which may be material. Such claims could relate to environmental damage, breach of contract, tax, bribery and employment matters, which could result in an unfavourable decision, including fines, sanctions, monetary damages or the inability to engage in certain operations or transactions. The outcome of such claims can be difficult to assess or quantify and may have a material adverse effect on the Company’s reputation, financial condition and results of operations. The defence to such claims may be costly and could divert management’s attention away from day-to-day operations.

Partner Misalignment

Joint venture partners operate a portion of Husky’s assets in which the Company has an ownership interest. This can reduce Husky’s control and ability to manage risks. Husky is at times dependent upon its partners for the successful execution of various projects. If a dispute with partners were to occur over the development and operation of a project or if partners were unable to fund their contractual share of the capital expenditures, a project could be delayed and the Company could be partially or totally liable for its partner’s share of the project.

Reserves Data and Future Net Revenue Estimates

The reserves data contained or referenced in this AIF represent estimates only. The accurate assessment of oil and gas reserves is critical to the continuous and effective management of the Company’s upstream assets. Reserves estimates support various investment decisions about the development and management of oil and gas properties. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flow therefrom are based upon a number of variable factors and assumptions, such as product prices, future operating and capital costs, historical production from the properties and the effects of regulation by government agencies, including with respect to royalty payments, all of which may vary considerably from actual results. All such estimates are to some degree uncertain, and classifications of reserves are only attempts to define the degree of uncertainty involved. All reserves estimates involve a degree of ambiguity and, at times, rely on indirect measurement techniques to estimate the size and recoverability of the resource. While new technologies have increased the accuracy of these techniques, there remains the potential for human or systemic error in recording and reporting the magnitude of the Company’s oil and gas reserves. For those reasons, the Company’s estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom may differ substantially from actual results. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets and could have a material adverse effect on the Company’s results of operations, financial condition, and ability to deliver on its growth business strategy.

Government Regulation

Given the scope and complexity of Husky’s operations, the Company is subject to regulation and intervention by governments at the federal, provincial, state and municipal levels in the countries in which it conducts its operations or exploratory activities. As these governments continually balance competing demands from different interest groups and stakeholders, the Company recognizes that the magnitude of regulatory risks has the potential to change over time. Changes in government policy, legislation or regulation could impact the Company’s existing and planned projects as well as impose costs of compliance and increase capital expenditures and operating expenses. Examples of the Company’s regulatory risks include, but are not limited to, uncertain or negative interactions with governments, uncertain energy policies, uncertain climate policies, uncertain environmental and safety policies, penalties, taxes, royalties, government fees, reserves access, limitations or increases in costs relating to the exportation of commodities, restrictions on the acquisition of exploration and production rights and land tenure, expropriation or cancellation of contract rights, limitations on control over the development and abandonment of fields and loss of licences to operate.

Environmental Regulation

Changes in environmental regulation could have a material adverse effect on Husky’s financial condition and results of operations by requiring increased capital expenditures and operating costs or by impacting the quality, formulation or demand of products, which may or may not be offset through market pricing.

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The scope and complexity of changes in environmental regulation make it challenging to forecast the potential impact to Husky. Husky has made projections of the impact of scenarios involving certain potential laws and regulations relating to climate change. Husky engages in dialogue on proposed changes, both directly and through industry associations, with the goal of ensuring the Company’s interests are recognized and Husky is sufficiently prepared to fully comply when new regulations come into force.

Husky anticipates further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, increased compliance costs and approval delays for critical licences and permits, which could have a material adverse effect on Husky’s financial condition and results of operations through increased capital and operating costs. See “Industry Overview - Environmental Regulations”.

Climate Change Regulation

The Company continues to monitor international and domestic efforts to address climate change, including international low carbon fuel standards and regulations and emerging regulations in the jurisdictions in which the Company operates.

The Alberta Climate Leadership Plan is expected to be implemented starting in 2017. This plan includes an economy wide carbon levy, rising to $30/ton in 2018 as well as a Carbon Competitiveness Regulation that will manage emissions at LFEs including the Ram River Gas Plant, Tucker Thermal Facility and Sunrise Energy Project. See “Industry Overview - Canadian Provincial Greenhouse Gas Regulations”. The regulations under this plan are currently under development and will cover all of the Company’s assets in Alberta. These regulations may materially adversely affect the Company’s results of operations in the province.

Climate change regulations to be developed in Saskatchewan will have to meet equivalency standards with the Canadian federal government and may materially adversely affect the Company’s results of operations in the province. See “Industry Overview - Canadian Provincial Greenhouse Gas Regulations”.

The cost of compliance with British Columbia’s $30 per ton carbon tax and the Renewable and Low Carbon Fuel Requirements Regulation may become material. Additionally, future regulations in support of British Columbia’s commitment under its Climate Leadership Plan may materially adversely affect the Company’s results of operations in British Columbia. See “Industry Overview - Canadian Provincial Greenhouse Gas Regulations”.

The Manitoba Climate Change and Green Economy Action Plan implementation may materially adversely affect Husky’s results of operations in Manitoba. See “Industry Overview - Canadian Provincial Greenhouse Gas Regulations”.

The Federal Government of Canada has announced its intention to commence developing a new federal climate change plan in consultation with the provinces. It is not clear how this new plan will be structured and what impacts it will have on Husky’s results of operations. Climate change regulations may become more onerous over time as governments implement policies to further reduce GHG emissions. Although the impact of emerging regulations is uncertain, they could have a material adverse effect on the Company’s financial condition and results of operations through increased capital and operating costs and change in demand for refined products.

The Company’s U.S. refining business may be materially adversely affected by the implementation of the EPA’s climate change rules or by future U.S. GHG legislation that applies to the oil and gas industry or the consumption of petroleum products. Such legislation or regulation could require the Company’s U.S. refining operations to significantly reduce emissions and/or purchase allowances, which may have a material adverse effect on the Company’s financial condition and results of operations through increased capital and operating costs and change in demand for refined products.

The U.S. RFS program, through the U.S. EPA specified RVO, requires refiners to add annually increasing amounts of renewable fuels to their petroleum products or to purchase RINs in lieu of such blending. See “Industry Overview - U.S. Renewable Fuels Standard”. Due to regulatory uncertainty and in part due to the U.S. fuel supply reaching the “blend wall” (the 10% limit prescribed by most automobile warranties), the price and availability of RINs has been volatile.

The Company complies with the RFS program in the US by blending renewable fuels manufactured by third parties and by purchasing RINs on the open market. The Company cannot predict the future prices of RINs and renewable fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. The Company’s financial position and results of operations could be adversely affected if it is unable to pass the costs of compliance on to its customers and if the Company pays significantly higher prices for RINs or blendstocks to comply with the RFS mandated standards.

Financial Risks

The Company’s financial risks are largely related to commodity price risk, foreign currency risk, interest rate risk, counterparty credit risk and liquidity risk. From time to time, the Company uses derivative financial instruments to manage its exposure to these risks. These derivative financial instruments are not intended for trading or speculative purposes.

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Commodity Price Risk

In certain instances, the Company uses derivative commodity instruments and futures contracts on commodity exchanges, including commodity put and call options under a short-term hedging program, to manage exposure to price volatility on a portion of its refined product, oil and gas production, and inventory or volumes in long distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and natural gas.

The Company’s results will be impacted by a decrease in the price of crude oil and natural gas inventory. The Company has crude oil inventories that are feedstock, held at terminals or part of the in-process inventories at its refineries and at offshore sites. The Company also has natural gas inventory that could have an impact on earnings based on changes in natural gas prices. All these inventories are subject to a lower of cost or net realizable value test on a monthly basis.

Foreign Currency Risk

The Company’s results are affected by the exchange rates between various currencies including the Canadian and U.S. dollars. The majority of the Company’s expenditures are in Canadian dollars while the majority of the Company’s revenues are received in U.S. dollars from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in the Company’s U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. The fluctuations in exchange rates are beyond the Company’s control and could have a material adverse effect on the Company’s results of operations and financial condition.

The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. dollar denominated revenue to hedge against these potential fluctuations. The Company also designates its U.S denominated debt as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency.

Interest Rate Risk

Interest rate risk is the impact of fluctuating interest rates on financial condition. In order to manage interest rate risk and the resulting interest expense, the Company mitigates some of its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt through the use of its credit facilities and various financial instruments. The optimal mix maintained will depend on market conditions. The Company may also enter into interest rate swaps from time to time as an additional means of managing current and future interest rate risk.

Counterparty Credit Risk

Credit risk represents the financial loss that the Company would suffer if the Company’s counterparties in a transaction fail to meet or discharge their obligation to the Company. The Company actively manages this exposure to credit and contract execution risk from both a customer and a supplier perspective. Internal credit policies govern the Company’s credit portfolio and limit transactions according to a counterparty’s and a supplier’s credit quality. Counterparties for financial derivatives transacted by the Company are generally major financial institutions or counterparties with investment grade credit ratings.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. The Company’s process for managing liquidity risk includes ensuring, to the extent possible, that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facilities and the availability to raise capital from various debt and equity capital markets under its shelf prospectuses. The availability of capital under its shelf prospectuses is dependent on market conditions at the time of sale.

Debt Covenants

The Company’s credit facilities include financial covenants, which include a debt to capital covenant. If the Company does not comply with the covenants under these credit facilities, there is a risk that repayment could be accelerated.

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Competition

The energy industry is highly competitive with respect to gaining access to the resources required to increase oil and gas reserves and production and gain access to markets. The Company competes with others to acquire prospective lands, retain drilling capacity and field operating and construction services, obtain sufficient pipeline and other transportation capacity, gain access to and retain adequate markets for its products and services and gain access to capital markets. The Company’s ability to successfully complete development projects could be adversely affected if it is unable to acquire economic supplies and services due to competition. Subsequent increases in the cost of or delays in acquiring supplies and services could result in uneconomic projects. The Company’s competitors comprise all types of energy companies, some of which have greater resources.

Credit Rating Risk

Credit ratings affect Husky’s ability to obtain short-term and long-term financing and the cost of such financing. Additionally, the ability of Husky to engage in ordinary course derivative or hedging transactions and maintain ordinary course contracts with customers and suppliers on acceptable terms depends on Husky’s credit ratings. A reduction in the current rating on Husky’s debt by one or more of its rating agencies, particularly a downgrade below investment grade ratings, or a negative change in Husky’s ratings outlook could adversely affect Husky’s cost of financing and its access to sources of liquidity and capital. Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings accorded to Husky’s securities by the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

General Economic Conditions

General economic conditions may have a material adverse effect on the Company’s results of operations and financial condition. A decline in economic activity will reduce demand for petroleum products and adversely affect the price the Company receives for its commodities. The Company’s cash flow could decline, assets could be impaired, future access to capital could be restricted and major development projects could be delayed or abandoned.

Cost or Availability of Oil and Gas Field Equipment

The cost or availability of oil and gas field equipment may adversely affect the Company’s ability to undertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including land and offshore drilling rigs, land and offshore geological and geophysical services, engineering and construction services and construction materials. These materials and services may not be available when required at reasonable prices.

Climatic Conditions

Extreme climatic conditions may have material adverse effects on results of operations. Weather and climate affect demand, and therefore, the predictability of the demand for energy is affected to a large degree by the predictability of weather and climate. In addition, the Company’s exploration, production and construction operations, or disruptions to the operations of major customers or suppliers, can be affected by extreme weather. This may result in cessation or diminishment of production, delay of exploration and development activities or delay of plant construction. All of these could potentially cause material adverse effects on the Company’s results of operations and financial condition.

The Company operates in some of the harshest environments in the world, including offshore in the Atlantic Region. Climate change may increase severe weather conditions in these locations including winds, flooding and variable temperatures, which are contributing to the melting of Northern ice and increased creation of icebergs. Icebergs off the coast of Newfoundland and Labrador may threaten offshore oil production facilities, causing damage to equipment and possible production disruptions, spills, asset damage and human impacts. The Company has in place a number of policies to protect people, equipment and the environment in the event of extreme weather conditions and ice melt conditions.

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The Company’s Atlantic Region business unit has a robust ice management program, which uses a range of resources including a dedicated ice surveillance aircraft, as well as synergistic relationships with government agencies including Environment Canada, the Coast Guard and Canadian Ice Service. Regular ice surveillance flights commence in February and continue until the threat has abated. In addition, Atlantic Region operators employ a series of supply and support vessels to actively manage ice and icebergs. These vessels are equipped with a variety of ice management tools including towing ropes, towing nets and water cannons. The Company also maintains a series of ad-hoc relationships with contractors, allowing the quick mobilization of additional resources as required.

Financial Controls

While the Company has determined that its disclosure controls and procedures and internal controls over financial reporting are effective, such controls can only provide reasonable assurance with respect to financial statement preparation and disclosure. Failure to prevent, detect and correct misstatements could have a material adverse effect on the Company’s results of operations and financial condition.

Cybersecurity Threats

As an oil and gas producer, the Company’s ability to operate effectively is dependent upon developing and maintaining information systems and infrastructure that support the financial and general operating aspects of the business. Concurrently, the oil and gas industry has become the subject of increased levels of cybersecurity threats.

The Company has security measures, policies and controls designed to protect and secure the integrity of its information technology systems. The Company takes a proactive approach by continuing to invest in technology, processes and people to help minimize the impact of the changing cyber landscape and enhance the Company’s resilience to cyber incidents. However, cybersecurity threats frequently change and require ongoing monitoring and detection capabilities. Such cybersecurity threats include unauthorized access to information technology systems due to hacking, viruses and other causes for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption by third parties. Cyber-attacks could result in the loss or exposure of confidential information related to retail credit card information, personnel files, exploration activities, corporate actions, executive officer communications and financial results. The significance of any such event is difficult to quantify, but if the breach is material in nature, it could adversely affect the financial performance of the Company, its operations, its reputation and standing and expose it to regulatory consequences and claims of third-party damage, all of which could materially adversely affect the Company’s results of operations and financial condition if the situation is not resolved in a timely manner, or if the financial impact of such adverse effects is not alleviated through insurance policies.

Although to date the Company has not experienced any material losses relating to cyber attacks or other information security breaches, there can be no assurance that the Company will not incur such losses in the future. The Company’s risk and exposure to these matters cannot be fully mitigated because of, among other things, the evolving nature of these threats. The Audit Committee of the Company’s Board of Directors has oversight of the Company’s risk mitigation strategies related to cybersecurity.

Skilled Workforce Shortage

Successful execution of Husky’s strategy is dependent on ensuring our workforce possesses the appropriate skill level. There is a risk that the Company may have difficulty attracting and retaining personnel with the required skill levels. Failure to attract and retain personnel with the required skill levels could have a material adverse effect on the Company’s results of operations.

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HUSKY EMPLOYEES

The number of Husky’s permanent employees was as follows:

As at December 31,
2016		2015		2014
	5,150		5,552		5,774

DIVIDENDS

The following table shows the aggregate amount of the dividends declared payable per share in respect of its last three years ended December 31, for the Company’s common shares, Series 1 Preferred Shares, Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares and Series 7 Preferred Shares:

	2016		2015		2014
Dividends per Common Share	$	—	$	0.90	$	1.20
Dividends per Series 1 Preferred Share	$	0.73	$	1.11	$	1.11
Dividends per Series 2 Preferred Share	$	0.42	$	—	$	—
Dividends per Series 3 Preferred Share	$	1.13	$	1.19	$	—
Dividends per Series 5 Preferred Share	$	1.13	$	0.90	$	—
Dividends per Series 7 Preferred Share	$	1.15	$	0.62	$	—

Dividend Policy and Restrictions

The declaration and payment of dividends are at the discretion of the Board of Directors, which will consider earnings, commodity price outlook, future capital requirements and financial condition of Husky, the satisfaction of the applicable solvency test in Husky’s governing corporate statute, the Business Corporations Act (Alberta) and other relevant factors.

Common Share Dividends

Shareholders have the ability to receive dividends in common shares or in cash. Quarterly dividends are declared in an amount expressed in dollars per common share and can be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume weighted average trading price of the common shares on the principal stock exchange on which the common shares are traded. The volume weighted average trading price of the common shares is calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares. With falling oil prices in 2015, the Board of Directors introduced in the third quarter of 2015, a stock dividend in lieu of cash. This dividend was paid on January 11, 2016. With the persistent downward pressure on oil prices and the extended “lower for longer” outlook, in the fourth quarter of 2015, the Board of Directors suspended the Company’s quarterly dividend on its common shares. There were no common shares dividends declared in the year 2016 (year ended December 31, 2015 - $1,181 million).

Husky’s dividend policy will continue to be reviewed and there can be no assurance that further dividends will be declared or the amount of any future dividend.

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Series 1 Preferred Share Dividends

Holders of Series 1 Preferred Shares were entitled to receive a cumulative quarterly fixed dividend, payable on the last day of March, June, September and December in each year, of 4.45 percent annually for the initial period ending March 31, 2016, as and when declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the 5-year Government of Canada bond yield plus 1.73 percent. Holders of Series 1 Preferred Shares had the right, at their option, to convert their shares into Series 2 Preferred Shares, subject to certain conditions, on March 31, 2016. In the first quarter of 2016, Husky announced it did not intend to exercise its right to redeem the Series 1 Preferred Shares on March 31, 2016. As a result, the holders of the Series 1 Preferred Shares had the right to choose to retain any or all of their Series 1 Preferred Shares and continue to receive an annual fixed rate dividend paid quarterly, or convert, on a one-for-one basis, any or all of their Series 1 Preferred Shares into Series 2 Preferred Shares, and receive a floating rate quarterly dividend. Holders of Series 1 Preferred Shares who retained their shares will receive the new fixed rate quarterly dividend applicable to the Series 1 Preferred Shares of 2.404 percent for the five year period commencing March 31, 2016 to, but excluding, March 31, 2021. Effective March 31, 2016, Husky had 10,435,932 Series 1 Preferred Shares issued and outstanding. Holders of the Series 1 Preferred Shares will have the opportunity to convert their shares again on March 31, 2021, and every five years thereafter as long as the shares remain outstanding.

Series 2 Preferred Share Dividends

Holders of the Series 2 Preferred Shares are entitled to receive a cumulative quarterly floating rate dividend, payable on the last day of March, June, September and December in each year, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 1.73 percent as and when declared by the Board of Directors. Effective March 31, 2016, Husky Energy had 1,564,068 Series 2 Shares issued and outstanding. Holders of the Series 2 Shares will have the opportunity to convert their shares again on March 31, 2021, and every five years thereafter as long as the shares remain outstanding.

Series 3 Preferred Share Dividends

Holders of the Series 3 Shares are entitled to receive a cumulative quarterly fixed dividend, payable on the last day of March, June, September and December in each year, of 4.50 percent annually for the initial period ending December 31, 2019 as declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.13 percent. Holders of Series 3 Shares will have the right, at their option, to convert their shares into Series 4 Preferred Shares, subject to certain conditions, on December 31, 2019 and on December 31 every five years thereafter. Holders of the Series 4 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.13 percent.

Series 5 Preferred Share Dividends

Holders of the Series 5 Preferred Shares are entitled to receive a cumulative quarterly fixed dividend, payable on the last day of March, June, September and December in each year, of 4.50 percent annually for the initial period ending March 31, 2020 as declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.57 percent. Holders of Series 5 Preferred Shares will have the right, at their option, to convert their shares into Series 6 Preferred Shares, subject to certain conditions, on March 31, 2020 and on March 31 every five years thereafter. Holders of the Series 6 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.57 percent

Series 7 Preferred Share Dividends

Holders of the Series 7 Preferred Shares are entitled to receive a cumulative fixed dividend, payable on the last day of March, June, September and December in each year, of 4.60 percent annually for the initial period ending June 30, 2020 as declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.52 percent. Holders of the Series 7 Preferred Shares will have the right, at their option, to convert their shares into Series 8 Preferred Shares, subject to certain conditions, on June 30, 2020 and on June 30 every five years thereafter. Holders of the Series 8 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.52 percent.

AIF 2016 Page 82

DESCRIPTION OF CAPITAL STRUCTURE

Common Shares

Husky is authorized to issue an unlimited number of no par value common shares. The holders of common shares are entitled to receive notice of and attend all meetings of shareholders, except meetings at which only holders of a specified class or series of shares are entitled to vote, and are entitled to one vote per common share held. Holders of common shares are also entitled to receive dividends as declared by the Board of Directors on the common shares payable in whole or in part as a stock dividend in fully paid and non-assessable common shares or by the payment of cash. Holders are also entitled to receive the remaining property of Husky upon dissolution in equal rank with the holders of all other common shares.

If the Board of Directors declares a dividend on the common shares payable in whole or in part as a stock dividend, unless otherwise determined by the Board of Directors of Husky in respect of a particular dividend, the value of the common shares for purposes of each stock dividend declared by the Board of Directors of Husky shall be deemed to be the volume weighted average trading price of the common shares on the principal stock exchange on which the common shares are traded, calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares.

In the event the stock dividend is to be issued pursuant to Husky’s Stock Dividend Program, shareholders of record wishing to accept a payment of the stock dividend, and of future stock dividends declared by the Board of Directors in the form of common shares pursuant to Husky’s Stock Dividend Program, are required to complete and deliver to Husky’s transfer agent a Stock Dividend Confirmation Notice at least five business days prior to the record date of a declared dividend. The Stock Dividend Confirmation Notice permits shareholders to confirm that they will accept common shares as payment of the dividend on all or a stated number of their common shares. A Stock Dividend Confirmation Notice will remain in effect for all stock dividends on the common shares to which it relates and which are held by the shareholder unless the shareholder delivers a revocation notice to Husky’s transfer agent, in which case the Stock Dividend Confirmation Notice will not be effective for any dividends having a declaration date that is more than five business days following receipt of the revocation notice by Husky’s transfer agent. In the event a shareholder fails to deliver a Stock Dividend Confirmation Notice at least five business days prior to the record date of a declared dividend, or delivers a Stock Dividend Confirmation Notice confirming that the holder of common shares accepts the common shares as payment of the dividend on some but not all of the holder’s common shares, the dividend on common shares for which no Stock Dividend Confirmation Notice was delivered or the dividend on those of the holder’s common shares in respect of which the holder did not deliver a Stock Dividend Confirmation Notice, will be paid in cash. See “Dividends - Dividend Policy and Restrictions - Common Share Dividends”.

Preferred Shares

Husky is authorized to issue an unlimited number of no par value preferred shares. The preferred shares as a class have attached thereto the rights, privileges, restrictions and conditions set forth below.

The preferred shares may from time to time be issued in one or more series, and the Board of Directors may fix from time to time before such issue the number of preferred shares which is to comprise each series and the designation, rights, privileges, restrictions and conditions attached to each series of preferred shares including, without limiting the generality of the foregoing, any voting rights, the rate or amount of dividends or, the method of calculating dividends, the dates of payment thereof, the terms and conditions of redemption, purchase and conversion if any, and any sinking fund or other provision.

The preferred shares of each series shall, with respect to the payment of dividends and the distribution of assets or return of capital in the event of liquidation, dissolution or winding up of Husky, whether voluntary or involuntary, or any other return of capital or distribution of assets of Husky amongst its shareholders for the purpose of winding up its affairs, be entitled to preference over the common shares of Husky and over any other shares of Husky ranking by their terms junior to the preferred shares of that series. The preferred shares of any series may also be given such other preferences over the common shares of Husky and any other such preferred shares.

If any cumulative dividends or amounts payable on the return of capital in respect of a series of preferred shares are not paid in full, all series of preferred shares shall participate ratably in respect of accumulated dividends and return of capital.

AIF 2016 Page 83

In 2011, Husky issued 12 million Series 1 Preferred Shares and authorized the issuance of 12 million Series 2 Preferred Shares. In 2014, Husky issued 10 million Series 3 Preferred Shares and authorized the issuance of 10 million Series 4 Preferred Shares. In 2015, Husky issued 8 million Series 5 Preferred Shares and 6 million Series 7 Preferred Shares and authorized the issuance of 8 million Series 6 Preferred Shares and 6 million Series 8 Preferred Shares. See “Dividends - Dividend Policy and Restrictions - Series 1 Preferred Share Dividends” and “Dividends - Dividend Policy and Restrictions - Series 2 Preferred Share Dividends” and “Dividends - Dividend Policy and Restrictions - Series 3 Preferred Share Dividends” and “Dividends - Dividend Policy and Restrictions - Series 5 Preferred Share Dividends” and “Dividends - Dividend Policy and Restrictions - Series 7 Preferred Share Dividends”. None of the issued preferred shares are entitled to vote, except in accordance with the provisions of the Business Corporations Act (Alberta).

Liquidity Summary

The following information relating to Husky’s credit ratings is provided as it relates to Husky’s financing costs, liquidity and operations. Specifically, credit ratings affect Husky’s ability to obtain short-term and long-term financing and the cost of such financing. Additionally, the ability of Husky to engage in certain collateralized business activities on a cost effective basis depends on Husky’s credit ratings. A reduction in the current rating on Husky’s debt by one or more of its rating agencies, particularly a downgrade below investment grade ratings, or a negative change in Husky’s ratings outlook could adversely affect Husky’s cost of financing and its access to sources of liquidity and capital. In addition, changes in credit ratings may affect Husky’s ability to enter, and the associated costs of entering, (i) into ordinary course derivative or hedging transactions, which may require Husky to post additional collateral under certain of its contracts if certain adverse events occur with respect to credit ratings, and (ii) into and maintaining ordinary course contracts with customers and suppliers on acceptable terms.

	Standard and Poor’s Rating Services	Moody’s Investor Service (“Moody’s”)	Dominion Bond Rating Services Limited
Outlook/Trend	Stable	Stable	Stable
Senior Unsecured Debt	BBB+	Baa2	A(low)
Series 1 Preferred Shares	P-2(low)		Pfd-2(low)
Series 2 Preferred Shares	P-2(low)		Pfd-2(low)
Series 3 Preferred Shares	P-2(low)		Pfd-2(low)
Series 5 Preferred Shares	P-2(low)		Pfd-2(low)
Series 7 Preferred Shares	P-2(low)		Pfd-2(low)
Commercial Paper			R-1(low)

Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings accorded to Husky’s securities by the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future, if in its judgment, circumstances so warrant. The Company pays an annual fee to Standard and Poor’s, Moody’s and Dominion Bond Rating Services Limited. Additionally, Husky pays a fee to credit rating agencies in order to receive a rating for debt or equity instruments upon issuance.

Moody’s

Moody’s long-term credit ratings are on a rating scale that ranges from Aaa (highest) to C (lowest). A rating of Baa2 by Moody’s is within the fourth highest of nine categories and is assigned to debt securities which are considered medium-grade (i.e., they are subject to moderate credit risk). Such debt securities may possess certain speculative characteristics. The addition of a 1, 2 or 3 modifier after a rating indicates the relative standing within a particular rating category. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates a ranking in the lower end of that generic rating category.

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Standard and Poor’s

Standard and Poor’s long-term credit ratings are on a rating scale that ranges from AAA (highest) to D (lowest). A rating of BBB+ by Standard & Poor’s is within the fourth highest of ten categories and indicates that the obligation exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. The addition of a plus (+) or minus (-) designation after a rating indicates the relative standing within the major rating categories.

Standard and Poor’s began rating Husky’s Series 1 Preferred Shares and Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares and Series 7 Preferred Shares on its Canadian preferred share scale on March 18, 2011, December 9, 2014, March 12, 2015 and June 17, 2015, respectively. Preferred share ratings are a forward-looking opinion about the creditworthiness of an issuer with respect to a specific preferred share obligation. There is a direct correspondence between the ratings assigned on the preferred share scale and Standard & Poor’s ratings scale for long-term credit ratings. According to Standard and Poor’s ratings system, a P-2 (low) rating on the Canadian preferred share rating scale is equivalent to a BBB- rating on the long-term credit rating scale.

Dominion Bond Rating Service

Dominion Bond Rating Service’s long-term credit ratings are on a rating scale that ranges from AAA (highest) to D (lowest). A rating of A (low) by Dominion Bond Rating Service is within the third highest of ten categories and is assigned to debt securities considered to be of good credit quality. The capacity for payment of financial obligations is substantial, but of lesser credit quality than that of higher rated securities. Entities in the A category may be vulnerable to future events, but qualifying negative factors are considered manageable. The assignment of a “(high)” or “(low)” modifier within each rating category indicates relative standing within such category.

Dominion Bond Rating Service began rating Husky’s Series 1 Preferred Shares and Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares, and Series 7 Preferred Shares on its Canadian preferred share scale on March 18, 2011, December 9, 2014, March 12, 2015 and June 17, 2015, respectively. Preferred share ratings are meant to give an indication of the risk that an issuer will not fulfill its full obligations in a timely manner, with respect to both dividend and principal commitments. Dominion Bond Rating Service preferred share ratings range from Pdf-1 (highest) to D (lowest). According to the Dominion Bond Rating Service ratings system, preferred shares rated Pfd-2 are of satisfactory credit quality where protection of dividends and principal is still substantial, but earnings, the balance sheet and coverage ratios are not as strong as Pfd-1 rated companies.

Dominion Bond Rating Service began rating Husky’s commercial paper on September 4, 2014. Credit ratings on commercial paper are on a short-term debt rating scale that ranges from R-1 (high) to D1 representing the range of such securities rated from highest to lowest qualify. A rating of R-1 (low) by Dominion Bond Rating Service is the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality. The capacity for the payment of short-term financial obligations as they become due is substantial with overall strength not as favourable as higher rating categories. Entities in this category may be vulnerable to future events, but qualifying negative factors are considered manageable. The R-1 and R-2 commercial paper categories are denoted by (high), (middle) and (low) designations.

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MARKET FOR SECURITIES

Husky’s common shares, Series 1 Preferred Shares, Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares, and Series 7 Preferred Shares are listed and posted for trading on the Toronto Stock Exchange (“TSX”) under the respective trading symbols “HSE”, “HSE.PR.A”, “HSE.PR.B”, “HSE.PR.C”, “HSE.PR.E” and “HSE.PR.G”. The Series 1 Preferred Shares began trading on the TSX on March 18, 2011. The Series 2 Preferred Shares began trading on the TSX on April 1, 2016. The Series 3 Preferred Shares began trading on the TSX on December 9, 2014. The Series 5 Preferred Shares began trading on the TSX on March 12, 2015. The Series 7 Preferred Shares began trading on the TSX on June 17, 2015.

The following table discloses the trading price range and volume of Husky’s common shares traded on the TSX during Husky’s financial year ended December 31, 2016:

	High		Low		Volume (000’s)
January		14.72		11.34		38,143
February		14.76		11.50		35,638
March		17.09		15.02		43,899
April		18.10		14.63		38,707
May		15.95		14.35		33,598
June		16.90		14.45		29,757
July		16.14		15.01		16,719
August		17.22		15.03		16,204
September		16.49		15.06		18,871
October		16.93		14.20		25,726
November		15.88		13.92		23,410
December		17.35		15.70		38,263

The following table discloses the trading price range and volume of the Series 1 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2016:

	High		Low		Volume (000’s)
January		13.37		8.18		319
February		8.95		7.80		546
March		10.81		8.45		727
April		11.41		10.06		332
May		11.79		10.99		495
June		12.51		11.02		405
July		12.04		11.09		377
August		12.76		11.83		167
September		12.26		11.74		203
October		12.35		11.62		295
November		12.79		11.60		314
December		13.45		12.12		562

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The following table discloses the trading price range and volume of the Series 2 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2016:

	High		Low		Volume (000’s)
April		10.51		9.00		28
May		10.94		10.03		26
June		11.54		10.20		71
July		11.50		10.10		28
August		11.90		10.96		23
September		11.98		11.04		33
October		11.75		11.03		29
November		12.25		11.36		26
December		13.15		11.56		42

The following table discloses the trading price range and volume of the Series 3 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2016:

	High		Low		Volume (000’s)
January		18.41		12.99		340
February		15.37		13.02		181
March		17.00		13.86		150
April		18.20		16.40		152
May		18.00		16.94		140
June		19.24		16.88		198
July		18.32		17.40		139
August		19.91		18.20		95
September		19.62		19.04		117
October		19.94		19.00		267
November		20.48		19.30		256
December		21.83		20.24		224

The following table discloses the trading price range and volume of the Series 5 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2016:

	High		Low		Volume (000’s)
January		19.38		13.50		303
February		16.24		14.29		251
March		18.90		15.68		234
April		20.27		18.37		173
May		20.10		19.02		137
June		20.97		18.66		133
July		19.91		19.02		96
August		21.39		19.85		105
September		21.31		20.62		146
October		22.02		20.90		202
November		22.23		20.86		240
December		22.99		21.46		249

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The following table discloses the trading price range and volume of the Series 7 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2016:

	High		Low		Volume (000’s)
January		19.36		13.61		215
February		16.40		14.44		151
March		19.07		15.77		101
April		20.23		18.24		102
May		20.15		18.50		82
June		20.83		18.47		190
July		20.11		19.20		220
August		21.99		20.06		191
September		21.41		20.99		91
October		21.98		20.85		109
November		22.44		21.24		201
December		23.09		21.39		215

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DIRECTORS AND OFFICERS

The following are the names and residences of the directors and officers of Husky as of the date of this AIF, their positions and offices with Husky and their principal occupations for at least the five preceding years. Each director will hold office until the Company’s next annual meeting or until his or her successor is appointed or elected.

Directors

Name & Residence	Office or Position	Principal Occupation During Past Five Years
Li, Victor T.K. Hong Kong Special Administrative Region	Co-Chair Director of Husky since August 2000	Mr. Li is the Group Co-Managing Director and Deputy Chairman of CK Hutchison Holdings Limited. He is also the Managing Director and Deputy Chairman of Cheung Kong Property Holdings Limited. He is also the Chairman and Executive Director of Cheung Kong Infrastructure Holdings Limited and CK Life Sciences Int’l., (Holdings) Inc., a Non-Executive Director of Power Assets Holdings Limited and HK Electric Investments Manager Limited which is the trustee-manager of HK Electric Investments, and a Non-Executive Director and the Deputy Chairman of HK Electric Investments Limited. Mr. Li is also the Deputy Chairman of Li Ka Shing Foundation Limited, Li Ka Shing (Overseas) Foundation and Li Ka Shing (Canada) Foundation, and a Non-Executive Director of The Hongkong and Shanghai Banking Corporation Limited.
		Mr. Li serves as a member of the Standing Committee of the 12th National Committee of the Chinese People’s Political Consultative Conference of the People’s Republic of China. He is also a member of the Commission on Strategic Development of the Hong Kong Special Administrative Region and Vice Chairman of the Hong Kong General Chamber of Commerce. Mr. Li is the Honorary Consul of Barbados in Hong Kong.
		Mr. Li holds a Bachelor of Science degree in Civil Engineering and a Master of Science degree in Civil Engineering, both received from Stanford University in 1987. He obtained an honorary degree, Doctor of Laws, honoris causa (LL.D.) from The University of Western Ontario in 2009.
Fok, Canning K.N. Hong Kong Special Administrative Region	Co-Chair and Chair of the Compensation Committee	Mr. Fok is an Executive Director and Group Co-Managing Director of CK Hutchison Holdings Limited.
	Director of Husky since August 2000	Mr. Fok is Chairman and a Director of Hutchison Telecommunications Hong Kong Holdings Limited, Hutchison Telecommunications (Australia) Limited, Hutchison Port Holdings Management Pte. Limited as the trustee-manager of Hutchison Port Holdings Trust, Power Assets Holdings Limited, HK Electric Investments Manager Limited as the trustee-manager of HK Electric Investments, and HK Electric Investments Limited. Mr. Fok is Deputy Chairman and an Executive Director of Cheung Kong Infrastructure Holdings Limited and an Alternate Director to a Director of Hutchison Telecommunications Hong Kong Holdings Limited.
		Mr. Fok obtained a Bachelor of Arts degree from St. John’s University, Minnesota in 1974 and a Diploma in Financial Management from the University of New England, Australia in 1976. He has been a member of the Institute of Chartered Accountants in Australia (which amalgamated with the New Zealand Institute of Chartered Accountants to become Chartered Accountants Australia and New Zealand) since 1979 and has been a Fellow of the Chartered Accountants Australia and New Zealand since 2015.

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Bradley, Stephen E. Beijing, People’s Republic of China	Member of the Audit Committee and the Corporate Governance Committee	Mr. Bradley is a Director of Broadlea Group Ltd., Senior Consultant, ICAP (Asia Pacific) Ltd. and a Director of Swire Properties Ltd. (Hong Kong).
	Director of Husky since July 2010	Mr. Bradley entered the British Diplomatic Service in 1981 and served in various capacities including Director of Trade & Investment Promotions (Paris) from 1999 to 2002; Minister, Deputy Head of Mission & Consul-General (Beijing) from 2002 to 2003 and HM Consul-General (Hong Kong) from 2003 to 2008. Mr. Bradley also worked in the private sector as Marketing Director, Guinness Peat Aviation (Asia) from 1987 to 1988 and Associate Director, Lloyd George Investment Management (now part of BMO Global Asset Management) from 1993 to 1995. Mr. Bradley retired from the Diplomatic Service in 2009.
		Mr. Bradley obtained a Bachelor of Arts degree from Balliol College, Oxford University in 1980 and a post-graduate diploma from Fudan University, Shanghai in 1981. Mr. Bradley is a Member of the Hong Kong Securities and Investment Institute and an ICD.D with the Institute of Corporate Directors of Canada.
Ghosh, Asim Portugal	Director of Husky since May 2009	Mr. Ghosh has been on the Board of Directors of Husky Energy since May 2009 and was President & Chief Executive Officer from June 2010 until his retirement in December 2016.
		He is the former Managing Director and Chief Executive Officer of Vodafone Essar Limited. Under his leadership the cellular phone company grew from a virtual startup in 1998 to become one of the largest mobile companies in the world by subscribers.
		Mr. Ghosh started his career with Procter & Gamble in Canada and subsequently became a Senior Vice President of Carling O’Keefe. He later became co-founding Chief Executive Officer of Pepsi Food’s start up operations in India.
		He served in senior executive positions and as Chief Executive Officer of the AS Watson consumer packaged goods subsidiary of Hutchison Whampoa. From 1991 to 1998 he managed a group of 13 business units, and expanded the group’s operations from Hong Kong to China and Europe.
		Mr. Ghosh received his Master of Business Administration from Wharton School at the University of Pennsylvania, and obtained his undergraduate degree in Electrical Engineering from the Indian Institute of Technology.
Glynn, Martin J.G. British Columbia, Canada	Chair of the Corporate Governance Committee and a Member of the Compensation Committee	Mr. Glynn is a Director of Public Sector Pension Investment Board (PSP Investments), Sun Life Financial Inc., Sun Life Assurance Company of Canada and Chair of UBC Investment Management Trust Inc.
	Director of Husky since August 2000	Mr. Glynn was a Director from 2000 to 2006 and President and Chief Executive Officer of HSBC Bank USA N.A. from 2003 until his retirement in 2006. Mr. Glynn was a Director of HSBC Bank Canada from 1999 to 2006 and President and Chief Executive Officer from 1999 to 2003.
		Mr. Glynn obtained a Bachelor of Arts (Honours) degree from Carleton University, Canada in 1974 and a Master’s degree in Business Administration from the University of British Columbia in 1976.
Koh, Poh Chan Hong Kong Special Administrative Region	Director of Husky since August 2000	Ms. Koh is Finance Director of Harbour Plaza Hotel Management (International) Ltd. (a hotel management company).

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		Ms. Koh is qualified as a Fellow Member (FCA) of the Institute of Chartered Accountants in England and Wales and is an Associate of the Canadian Institute of Chartered Accountants (CPA, CA) and the Chartered Institute of Taxation in the U.K. (CTA).
		Ms. Koh graduated from the London School of Accountancy in 1971 and was admitted to the Institute of Chartered Accountants in England and Wales in 1973, to the Chartered Institute of Taxation in the UK in 1976 as well as the Institute of Chartered Accountants of Ontario, Canada in 1980.
Kwok, Eva L. British Columbia, Canada	Member of the Compensation Committee and the Corporate Governance Committee	Mrs. Kwok is Chairman, a Director and Chief Executive Officer of Amara Holdings Inc. (a private investment holding company). Mrs. Kwok is also a Director of CK Life Sciences Int’l., (Holdings) Inc. and Cheung Kong Infrastructure Holdings Limited. Mrs. Kwok is also a Director of the Li Ka Shing (Canada) Foundation.
	Director of Husky since August 2000	Mrs. Kwok was a Director of Shoppers Drug Mart Corporation from 2004 to 2006 and of the Bank of Montreal Group of Companies from 1999 until March 2009.
		Mrs. Kwok obtained a Master’s degree in Science from the University of London in 1967.
Kwok, Stanley T.L. British Columbia, Canada	Chair of the Health, Safety and Environment Committee	Mr. Kwok is a Director and President of Stanley Kwok Consultants (a planning and development company) and Amara Holdings Inc. He is an independent Non-Executive Director of CK Hutchison Holdings Limited.
	Director of Husky since August 2000	Mr. Kwok is a Director of the CTBC Bank of Canada and Element Lifestyle Retirement Inc.
		Mr. Kwok obtained a Bachelor of Science degree (Architecture) from St. John’s University, Shanghai in 1949, and an A.A. Diploma from the Architectural Association School of Architecture in London, England in 1954.
Ma, Frederick S. H. Hong Kong Special Administrative Region	Member of the Audit Committee and the Health, Safety and Environment Committee	Professor Ma has held senior management positions in international financial institutions and Hong Kong publicly listed companies in his career. He was also a former Principal Official with the Hong Kong Special Administrative Region Government.
	Director of Husky since July 2010	In addition to being a Director of Husky, he is currently the Non-Executive Chairman of MTR Corporation Limited (formerly Mass Transit Railway Corporation). He is currently a Non-Executive Director of COFCO Corporation.
		In July 2002, Professor Ma joined the Government of the Hong Kong Special Administrative Region as the Secretary for Financial Services and the Treasury. He assumed the post of Secretary for Commerce and Economic Development in July 2007, but resigned from the Government in July 2008 due to medical reasons. Professor Ma was appointed as a member of the International Advisory Council of China Investment Corporation in July 2009. In January 2013, he was appointed a member of the Global Advisory Council of the Bank of America. Professor Ma was appointed as an Honorary Professor of the School of Economics and Finance at the University of Hong Kong in October 2008. In August 2013, he was appointed as an Honorary Professor of the Faculty of Business Administration at the Chinese University of Hong Kong.
		Professor Ma obtained a Bachelor of Arts (Honours) degree in Economics and History from the University of Hong Kong in 1973, an Honorary Doctor of Social Sciences in October 2014 from Lingnan University and an Honorary Doctor of Social Sciences in October 2016 from City University of Hong Kong.

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Magnus, George C. Hong Kong Special Administrative Region	Member of the Audit Committee Director of Husky since July 2010	Mr. Magnus is a Non-Executive Director of CK Hutchison Holdings Limited and Cheung Kong Infrastructure Holdings Limited, and an independent Non-Executive Director of HK Electric Investments Manager Limited.
		Mr. Magnus acted as an Executive Director of Cheung Kong (Holdings) Limited from 1980 and as Deputy Chairman from 1985 until his retirement from these positions in October 2005. He served as Deputy Chairman of Hutchison Whampoa Limited from 1985 to 1993 and as Executive Director from 1993 to 2005.
		He also served as Chairman of Hongkong Electric Holdings Limited (now known as Power Assets Holdings Limited) from 1993 to 2005. He was a Non-Executive Director of Power Assets Holding Limited from 2005 to 2012 and then an independent Non-Executive Director until January 2014.
		Mr. Magnus obtained a Bachelor of Arts degree in 1959. He obtained a Master’s degree in Economics from King’s College, Cambridge University in 1963.
McGee, Neil D. Luxembourg	Member of the Health, Safety and Environment Committee Director of Husky since November 2012	Mr. McGee is the Managing Director of Hutchison Whampoa Europe Investments S.à r.l. He is an Executive Director of Power Assets Holdings Limited. Prior to his joining Hutchison Whampoa Europe Investments S.à r.l., he served as Group Finance Director of Power Assets Holdings Limited from 2006 to 2012, Chief Financial Officer of Husky Oil Limited from 1998 to 2000 and Chief Financial Officer of Husky Energy Inc. from 2000 to 2005.
		Prior to joining Husky Oil Limited in 1998, Mr. McGee held various financial, legal and corporate secretarial positions with the CK Hutchison Holdings Group. Mr. McGee holds a Bachelor of Arts degree and a Bachelor of Laws degree from the Australian National University.
Peabody, Robert J. Alberta, Canada	President & Chief Executive Officer Director since December 2016	Mr. Peabody became a member of the Board of Directors and President and Chief Executive Officer of Husky on December 5, 2016.
		Mr. Peabody was appointed Chief Operating Officer in 2006 and was responsible for leading Husky’s Upstream and Downstream segments, including Western Canada Conventional and Unconventional, Heavy Oil, Oil Sands, Atlantic Region and Exploration, as well as Refining and Upgrading operations. He was also responsible for the Safety, Engineering, Project Management and Procurement functions.
		Prior to joining Husky, he led four major businesses for BP plc in Europe and the United States. Mr. Peabody holds a BASc in Mechanical Engineering from the University of British Columbia and MSc in Management (Sloan Fellow) from Standford Univesity. Mr. Peabody is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).

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Russel, Colin S. Gloucestershire, United Kingdom	Member of the Audit Committee and the Health, Safety and Environment Committee Director of Husky since February 2008	Mr. Russel is the founder and a director of Emerging Markets Advisory Services Ltd. (a business advisory company). Mr. Russel is a Director of Cheung Kong Infrastructure Holdings Limited, CK Life Sciences Int’l., (Holdings) Inc. and ARA Asset Management Pte. Ltd. Mr. Russel was the Canadian Ambassador to Venezuela; Consul General for Canada in Hong Kong; Director for China of the Department of Foreign Affairs, Ottawa; Director for East Asian Trade in Ottawa; Senior Trade Commissioner for Canada in Hong Kong; Director for Japan Trade in Ottawa and was in the Trade Commissioner Service for Canada in Spain, Hong Kong, Morocco, the Philippines, London and India. Previously Mr. Russel was an international project manager with RCA Ltd., Canada and development engineer with AEI Ltd., UK.
		Mr. Russel received a degree in Electrical Engineering in 1962 and a Master’s degree in Business Administration in 1971, both from McGill University, Canada.
Shaw, Wayne E. Ontario, Canada	Member of the Corporate Governance Committee and the Health, Safety and Environment Committee	Mr. Shaw is the President of G.E. Shaw Investments ULC. Prior to his retirement in April 2013, he was a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors. Mr. Shaw is also a Director of the Li Ka Shing (Canada) Foundation.
	Director of Husky since August 2000	Mr. Shaw holds a Bachelor of Arts degree and a Bachelor of Laws degree, both received from the University of Alberta in 1967. He is a member of the Law Society of Upper Canada.
Shurniak, William Saskatchewan, Canada	Deputy Chair and Chair of the Audit Committee Director of Husky since August 2000	Mr. Shurniak was an independent Non-Executive Director of Hutchison Whampoa Limited until June 2015, when he became an independent Non-Executive Director of CK Hutchison Holdings Limited. From May 2005 to June 2011 he was a Director and Chairman of Northern Gas Networks Limited (a private distributor of natural gas in Northern England).
		Mr. Shurniak also held the following positions until his return to Canada in 2005: Director and Chairman of ETSA Utilities (a utility company) since 2000, Powercor Australia Limited (a utility company) since 2000, CitiPower Pty Ltd. (a utility company) since 2002, and a Director of Envestra Limited (a natural gas distributor) since 2000, CrossCity Motorways Pty Ltd. (an infrastructure and transportation company) since 2002 and Lane Cove Tunnel Company Pty Ltd. (an infrastructure and transportation company) since 2004.
		Mr. Shurniak obtained an Honorary Doctor of Laws degree from the University of Saskatchewan in May 1998 and from The University of Western Ontario in October 2000. On July 30, 2005, he was a recipient of the Saskatchewan Centennial Medal from the Lieutenant Governor of Saskatchewan. In 2009 he was awarded the Saskatchewan Order of Merit by the Government of the Province of Saskatchewan. In December 2012, Mr. Shurniak was a recipient of The Queen Elizabeth II Diamond Jubilee Medal from the Lieutenant Governor of Saskatchewan. On June 4, 2014, the University of Regina conferred an Honorary Doctor of Laws degree on Mr. Shurniak and on November 10, 2016 he was awarded the Meritorious Service Medal by the Governor General of Canada.

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Sixt, Frank J. Hong Kong Special Administrative Region	Member of the Compensation Committee Director of Husky since August 2000	Mr. Sixt is an Executive Director, Group Finance Director and Deputy Managing Director of CK Hutchison Holdings Limited. Mr. Sixt is also a Non-Executive Chairman of TOM Group Limited, an Executive Director of Cheung Kong Infrastructure Holdings Limited, a Director of Hutchison Telecommunications (Australia) Limited (HTAL) and an Alternate Director to a Director of HTAL, HK Electric Investments Manager Limited as the trustee-manager of HK Electric Investments and HK Electric Investments Limited. Mr. Sixt is also a Director of the Li Ka Shing (Canada) Foundation.
		Mr. Sixt obtained a Master’s degree in Arts from McGill University, Canada in 1978 and a Bachelor’s degree in Civil Law from Université de Montréal in 1978. He is a member of the Bar and of the Law Society of the Provinces of Quebec and Ontario, Canada.

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Officers

Name and Residence	Office or Position	Principal Occupation During Past Five Years
Jonathan M. McKenzie Alberta, Canada	Chief Financial Officer	Chief Financial Officer of Husky since April 2015. Chief Commercial Financial Officer of Irving Oil Ltd. from April 2011 to April 2015. Vice President & Controller of Suncor Energy Inc. from March 2009 to May 2011.
Girgulis, James D. Alberta, Canada	Senior Vice President, General Counsel & Secretary	Vice President, Legal & Corporate Secretary of Husky since August 2000. Senior Vice President, General Counsel & Secretary since April 2012.

As at February 15, 2017, the directors and officers of Husky, as a group, beneficially owned or controlled or directed, directly or indirectly, 889,740 common shares of Husky, representing less than one percent of the issued and outstanding common shares.

Conflicts of Interest

The officers and directors of Husky may also become officers and/or directors of other companies engaged in the oil and gas business generally and which may own interests in oil and gas properties in which Husky holds or may in the future, hold an interest. As a result, situations may arise where the interests of such directors and officers conflict with their interests as directors and officers of other companies. In the case of the directors, the resolution of such conflicts is governed by applicable corporate laws that require that directors act honestly, in good faith and with a view to the best interests of Husky and, in respect of the Business Corporations Act (Alberta), Husky’s governing statute that directors declare, and refrain from voting on, any matter in which a director may have a conflict of interest.

Corporate Cease Trade Orders or Bankruptcies

None of those persons who are directors or executive officers of Husky is or have been within the past ten years, a director, chief executive officer or chief financial officer of any company, including Husky and any personal holding companies of such person that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, for a period of more than 30 consecutive days, or after such persons ceased to be a director, chief executive officer or chief financial officer of the company was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, for a period of more than 30 consecutive days, which resulted from an event that occurred while such person was acting in such capacity.

In addition, none of those persons who are directors or executive officers of Husky is, or has been within the past ten years, a director or executive officer of any company, including Husky and any personal holding companies of such persons, that while such person was acting in that capacity, or within a year of that person ceasing to act in that capacity became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets, other than as follows. Mr. Glynn was director of MF Global Holdings Ltd. when it filed for Chapter 11 bankruptcy in the U.S. on October 31, 2011. Mr. Glynn is no longer a director of MF Global Holdings Ltd.

Individual Penalties, Sanctions or Bankruptcies

None of the persons who are directors or executive officers of Husky (or any personal holding companies of such persons) have, within the past ten years become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or were subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold his or her assets.

None of the persons who are directors or executive officers of the Company (or any personal holding companies of such persons) have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or have entered into a settlement agreement with a securities regulatory authority or been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

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AUDIT COMMITTEE

The members of Husky’s Audit Committee (the “Committee”) are William Shurniak (Chair), Stephen E. Bradley, Colin S. Russel, Frederick S.H. Ma and George C. Magnus. Each of the members of the Committee is independent in that each member does not have a direct or indirect material relationship with the Company. Multilateral Instrument 52-110 - “Audit Committees” provides that a material relationship is a relationship which could, in the view of the Company’s Board of Directors, reasonably interfere with the exercise of a member’s independent judgment.

The Committee’s Mandate provides that the Committee is to be comprised of at least three members of the Board, all of whom shall be independent and meet the financial literacy requirements of applicable laws and regulations. Each member of the Committee is financially literate in that each has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Company’s financial statements.

The education and experience of each Committee member that is relevant to the performance of his responsibilities as a Committee member is as follows.

William Shurniak (Chair) - Mr. Shurniak was an independent Non-Executive Director of Hutchison Whampoa Limited until June 2015, when he became an independent Non-Executive Director of CK Hutchison Holdings Limited, a newly listed company on The Stock Exchange of Hong Kong Limited. From May 2005 to June 2011 he was a Director and Chairman of Northern Gas Networks Limited (a private distributor of natural gas in Northern England).

Stephen E. Bradley - Mr. Bradley is a Director of Broadlea Group Ltd., Senior Consultant, ICAP (Asia Pacific) and a Director of Swire Properties Ltd. (Hong Kong).

Colin S. Russel - Mr. Russel is the founder and Managing Director of Emerging Markets Advisory Services Ltd. Mr. Russel is a director and an audit committee member of Cheung Kong Infrastructure Holdings Limited, CK Life Sciences Int’l., (Holdings) Inc. and ARA Asset Management Pte. Ltd.

Frederick S.H. Ma - Professor Ma has served in senior positions in the private sector and has held Principal Official positions (minister equivalent) with the Hong Kong Special Administrative Region Government. Professor Ma is currently a member of the International Advisory Council of China Investment Corporation, China’s Sovereign Fund, as well as an Honorary Professor of the University of Hong Kong.

George C. Magnus - Mr. Magnus is a Non-Executive Director of CK Hutchison Holdings Limited and Cheung Kong Infrastructure Holdings Limited and an independent Non-Executive Director of HK Electric Investments Manager Limited and HK Electric Investments Limited.

Husky’s Audit Committee Mandate is attached hereto as Schedule “A”.

External Auditor Service Fees

The following table provides information about the fees billed to the Company for professional services rendered by KPMG LLP, the Company’s external auditor, during the fiscal years indicated:

($ thousands)	2016		2015
Audit Fees		3,858		3,446
Audit-related Fees		158		615
Tax Fees		350		69
		4,366		4,130

Audit fees consist of fees for the audit of the Company’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings, including the Sarbanes-Oxley Act of 2002. Audit-related fees included fees for attest services not required by statute or regulation. Tax fees included fees for tax planning and various taxation matters.

The Committee has the sole authority to review in advance, and grant any appropriate pre-approvals, of all non-audit services to be provided by the independent auditors and to approve fees, in connection therewith. The Committee pre-approved all of the audit-related and tax services provided by KPMG LLP in 2016.

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LEGAL PROCEEDINGS

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these or other matters or amount which it may be required to pay by reason thereof would have a material adverse impact on its financial condition, results of operations or liquidity.

INTEREST OF MANAGEMENT AND OTHERS

IN MATERIAL TRANSACTIONS

None of the Company’s directors, executive officers or persons or companies that beneficially own or control or direct, directly or indirectly or a combination of both, more than 10 percent of Husky’s common shares, or their associates and affiliates, had any material interest, direct or indirect, in any transaction with the Company within the three most recently completed financial years or during the current financial year that has materially affected or would reasonably be expected to materially affect the Company.

TRANSFER AGENTS

AND REGISTRARS

Husky’s transfer agent and registrar is Computershare Trust Company of Canada. In the United States, the transfer agent and registrar is Computershare Trust Company, Inc. The registers for transfers of the Company’s common and preferred shares are maintained by Computershare Trust Company of Canada at its principal offices in the cities of Calgary, Alberta and Toronto, Ontario. Queries should be directed to Computershare Trust Company at 1-800-564-6253 or 1-514-982-7555.

INTERESTS OF EXPERTS

Certain information relating to the Company’s reserves included in this AIF has been calculated by the Company and audited and opined upon as at December 31, 2016 by Sproule. Sproule is an independent petroleum engineering consultant retained by Husky, and such reserves information has been so included in reliance on the opinion and analysis of Sproule, given upon the authority of said firm as experts in reserves engineering. The partners, employees and consultants of Sproule, as a group beneficially own, directly or indirectly, less than one percent of the Company’s securities of any class.

KPMG LLP are the auditors of the Company and have confirmed that they are independent with respect to the Company within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations and also that they are independent accountants with respect to the Company under all relevant U.S. professional and regulatory standards.

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration, principal shareholders of Husky’s common shares and a description of options to purchase common shares will be contained in Husky’s Management Information Circular prepared in connection with the annual meeting of shareholders to be held on May 5, 2017.

Additional financial information is provided in Husky’s audited consolidated financial statements and Management’s Discussion and Analysis (“MD&A”) for the most recently completed fiscal year ended December 31, 2016.

Additional information relating to Husky Energy Inc. is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

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READER ADVISORIES

Special Note Regarding Forward-Looking Statements

Certain statements in this document are forward-looking statements and information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and Section 27A of the U.S. Securities Act of 1933, as amended. The forward-looking statements contained in this document are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “estimated”, “intend”, “plan”, “projection”, “could”, “may”, “would”, “aim”, “vision”, “goals”, “objective”, “target”, “schedules” and “outlook”). In particular, forward-looking statements in this document include, but are not limited to, references to:

• with respect to the business, operations and results of the Company generally: the Company’s general strategic plans and growth strategies; the Company’s expected expenditures in 2017 on environmental site closure activities; expected effects of abandonment and reclamation costs, development costs, and operating costs on anticipated development or production activities on properties with no attributed reserves; scheduled timing of development of the Company’s proved and probable undeveloped reserves; expected sources of funding for future development costs; estimates of the forecasted costs of developing the Company’s proved and proved plus probable reserves as at December 31, 2016; the Company’s 2017 production estimates broken down by product type and location; and anticipated effects of and cost of compliance with certain future or proposed laws and regulations on the Company’s operations;

• with respect to the Company’s Asia Pacific Region: anticipated volumes of peak combined net sales volumes of gas and NGL from the BD, MDA, MBH and MDK fields; anticipated timing of signing the floating production vessel lease contract for, and first production at, the MDA, MBH, and MDK gas fields; anticipated timing of exploration and drilling plans at Block 15/33; anticipated timing of acquisition of seismic surveying data at the Taiwan exploration block; and anticipated timing of first production and reaching full gas sales rates from the BD field;

• with respect to the Company’s Oil Sands properties: anticipated range of daily production volumes from the Company’s Sunrise Energy Project for 2017;

• with respect to the Company’s Heavy Oil properties: the Company’s strategic plans for its Heavy Oil Thermal production and CHOPS production; capacity at Edam West; anticipated timing of first production from, and nameplate capacities of, the Company’s Rush Lake 2, Dee Valley, Spruce Lake Central, and Spruce Lake North heavy oil thermal projects; estimated daily production from Tucker Lake Thermal Project by 2019; anticipated timing and extent of evaluation drilling at McMullen Willow Creek Thermal Development, and anticipated timing of associated AER application; and anticipated timing of first production from, and nameplate capacity of, the Phase I Plant at McMullen Willow Creek Thermal Development and the conceptual development plan through to 2040;

• with respect to the Company’s Western Canadian oil and gas resource plays: growth strategies and development opportunities; the Company’s 2017 drilling plans for the Foothills operations; anticipated impact on sales capacity from, and timing of completion of, the Rainbow Lake processing plant modifications; and plan not to pursue any activity in the Northwest Territories in 2017;

• with respect to the Company’s Upstream Infrastructure and Marketing operating segment: planned expansion of HMLP’s gathering system network and Hardisty terminal, and anticipated benefits of such expansion; and

• with respect to the Company’s Downstream operating segment: anticipated timing of completion, outcome, and benefits of the reliability and profitability improvement projects at the Company’s Lima Refinery; plans to process bitumen from the Sunrise Energy Project; the Company’s 2017 plans for its asphalt distribution network, including increasing asphalt modification capacity, expanding U.S. retail sales, and marketing residual productions; anticipated benefits of expanded asphalt processing capacity; and anticipated timing of consolidation of the Company’s and Imperial Oil’s truck transport network.

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In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve and production estimates.

Although the Company believes that the expectations reflected by the forward-looking statements presented in this AIF are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources including third party consultants, suppliers, regulators and other sources. The material factors and assumptions used to develop the forward-looking statements include, but are not limited to:

• with respect to the business, operations and results of the Company generally: the absence of significant adverse changes to commodity prices, interest rates, applicable royalty rates and tax laws, and foreign exchange rates; the absence of significant adverse changes to energy markets, competitive conditions, the supply and demand for crude oil, natural gas, NGL and refined petroleum products, or the political, economic and social stability of the jurisdictions in which the Company operates; continuing availability of economical capital resources, labour and services; demand for products and cost of operations; the absence of significant adverse legislative and regulatory changes, in particular changes to the legislation and regulation governing fiscal regimes and environmental issues; and stability of general domestic and global economic, market and business conditions;

• with respect to the Company’s Asia Pacific Region, Atlantic Region, Oil Sands properties, Heavy Oil properties, Western Canadian oil and gas resource plays and Infrastructure and Marketing operations: the accuracy of future production rates and reserve estimates; the securing of sales agreements to underpin the commercial development and regulatory approvals for the development of the Company’s properties; the absence of significant delays of the procurement, development, construction or commissioning of the Company’s projects, for which the Company or a third party is the designated operator, that may result from the inability of suppliers to meet their commitments, lack of regulatory or third-party approvals or other governmental actions, harsh weather or other calamitous event; the absence of significant disruption of operations such as may result from harsh weather, natural disaster, accident, civil unrest or other calamitous event; the absence of significant unexpected technological or commercial difficulties that adversely affect exploration, development, production, processing or transportation; the sufficiency of budgeted capital expenditures in carrying out planned activities; and the absence of significant increases in the cost of major growth projects; and

• with respect to the Company’s Downstream operating segment: the absence of significant delays of the development, construction or commissioning of the Company’s projects that may result from the inability of suppliers to meet their commitments, lack of regulatory or third-party approvals or other governmental actions, harsh weather or other calamitous event; the absence of significant disruption of operations such as may result from harsh weather, natural disaster, accident, civil unrest or other calamitous event; the absence of significant unexpected technological or commercial difficulties that adversely affect processing or transportation; the sufficiency of budgeted capital expenditures in carrying out planned activities; and the absence of significant increase in the cost of major growth projects.

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Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Husky. The risks, uncertainties and other factors, many of which are beyond Husky’s control, that could cause actual results to differ (potentially significantly) from those expressed in the forward-looking statements include, but are not limited to:

• with respect to the business, operations and results of the Company generally: those risks, uncertainties and other factors described under “Risk Factors” in this AIF and throughout the Company’s MD&A for the year ended December 31, 2016; the demand for the Company’s products and prices received for crude oil and natural gas production and refined petroleum products; the economic conditions of the markets in which the Company conducts business; the exchange rate between the Canadian and U.S. dollar; the foreign currency risk relating to the Block 29/26 gas and liquids sales agreements which are denominated in Chinese Yen; the ability to replace reserves of oil and gas, whether sourced from exploration, improved recovery or acquisitions; potential actions of governments, regulatory authorities and other stakeholders that may impose operating costs or restrictions in the jurisdictions where the Company has operations; changes to royalty regimes; changes to government fiscal, monetary and other financial policies; changes in workforce demographics; and the cost and availability of capital, including access to capital markets at acceptable rates;

• with respect to the Company’s Asia Pacific Region, Atlantic Region, Oil Sands properties, Heavy Oil properties, Western Canadian oil and gas resource plays and the Infrastructure and Marketing operations: the availability of prospective drilling rights; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project development; the availability and cost of labour, technical expertise, material and equipment to efficiently, effectively and safely undertake capital projects; the costs to operate properties, plants and equipment in an efficient, reliable and safe manner; prevailing climatic conditions in the Company’s operating locations; regulations to deal with climate change issues; the competitive actions of other companies, including increased competition from other oil and gas companies; business interruptions because of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting the Company or other parties whose operations or assets directly or indirectly affect the Company and that may or may not be financially recoverable; the co-operation of business partners especially where the Company is not operator of production projects or developments in which it has an interest; the inability to obtain regulatory approvals to operate existing properties or develop significant growth projects; risk associated with transportation of production or product to market or transportation of feedstock to processing facilities resulting from an interruption in pipeline and other transportation services both owned and contracted, due to calamitous event or regulatory obligation; and the inability to reach estimated production levels from existing and future oil and gas development projects as a result of technological or commercial difficulties; the continued availability of third-party owned equipment for operations; and

• with respect to the Company’s Downstream operating segment: the costs to operate properties, plants and equipment in an efficient, reliable and safe manner; regulatory (environmental, license to operate, social and political) and prevailing climatic conditions in the Company’s operating locations; regulations to deal with climate change issues; the competitive actions of other companies, including increased competition from other oil and gas companies; business interruptions because of unexpected events such as fires, loss of containment, freeze-ups, equipment failures and other similar events affecting Husky or other parties whose operations or assets directly or indirectly affect the Company and that may or may not be financially recoverable; risk associated with transportation of production or product to market or transportation of feedstock to processing facilities resulting from an interruption in pipeline and other transportation services both owned and contracted, due to calamitous event or regulatory obligation; and the inability to obtain regulatory approvals to operate existing properties or develop significant growth projects.

These and other factors are discussed throughout this AIF and in the MD&A for the year ended December 31, 2016 available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

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In the discussions above, the Company has categorized the material factors and assumptions used to develop the forward-looking statements, and the risks, uncertainties and other factors that could influence actual results, by region, properties, plays and segments. These categories reflect the Company’s current views regarding the factors, assumptions, risks and uncertainties most relevant to the particular region, property, play or segment. Other factors, assumptions, risks or uncertainties could impact a particular region, property, play or segment, and a factor, assumption, risk or uncertainty categorized under a particular region, property, play or segment could also influence results with respect to another region, property, play or segment.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.

Non-GAAP Measures

This document contains the term “operating netback”, which is a common non-GAAP metric used in the oil and gas industry and is considered to be useful as a complementary measure in assessing the Company’s financial performance, efficiency and liquidity. This measurement assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. There are no comparable measures to this non-GAAP measure in accordance with IFRS, and it is therefore unlikely to be comparable to similar measures presented by other issuers. The operating netback was determined as gross revenue less royalties, production and operating expenses, and transportation expenses on a per unit basis.

Disclosure of Oil and Gas Information

Unless otherwise stated, reserve estimates in this document, have been prepared by internal qualified reserves evaluators in accordance with the Canadian Oil and Gas Evaluation Handbook, have an effective date of December 31, 2016 and represent Husky’s share. Unless otherwise noted, historical production numbers given represent Husky’s share.

The Company uses the term reserve replacement ratio, which is consistent with other oil and gas companies’ disclosures. Reserve replacement ratios for a given period are determined by taking the Company’s incremental proved reserve additions for that period divided by the Company’s upstream gross production for the same period. The reserve replacement ratio measures the amount of reserves added to a company’s reserve base during a given period relative to the amount of oil and gas produced during that same period. A company’s reserve replacement ratio must be at least 100 percent for the company to maintain its reserves. The reserve replacement ratio only measures the amount of reserves added to a company’s reserve base during a given period.

Note to U.S. Readers

The Company reports its reserves information in accordance with Canadian practices and specifically in accordance with National Instrument 51-101, “Standards of Disclosure for Oil and Gas Disclosure”, adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves information in accordance with Canadian disclosure requirements, it may use certain terms in that disclosure that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC.

All currency is expressed in Canadian dollars unless otherwise stated.

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Schedule A

Husky Energy Inc.

Audit Committee Mandate

Purpose

The Audit Committee (the “Committee”) is a committee of the Board of Directors (the “Board”) of Husky Energy Inc. (the “Corporation”). The Committee’s primary function is to assist the Board in carrying out its responsibilities with respect to:

1. the quarterly and annual financial statements and quarterly and annual MD&A, which are to be provided to shareholders and the appropriate regulatory agencies;

2. earnings press releases before the Corporation publicly discloses this information;

3. the system of internal controls that management has established;

4. the internal and external audit process;

5. the appointment of external auditors;

6. the appointment of qualified reserves evaluators or auditors;

7. the filing of statements and reports with respect to the Corporation’s oil and gas reserves; and

8. the identification, management and mitigation of major financial risk exposures of the Corporation.

In addition, the Committee provides an avenue for communication between the Board and each of the Chief Financial Officer of the Corporation and other senior financial management, internal audit, the external auditors, external qualified reserves evaluators or auditors and internal qualified reserves evaluators. It is expected that the Committee will have a clear understanding with the external auditors and the external reserve evaluators or auditors that an open and transparent relationship must be maintained with the Committee.

While the Committee has the responsibilities and powers set forth in this Mandate, the role of the Committee is oversight. The members of the Committee are not full time employees of the Corporation and may or may not be accountants or auditors by profession or experts in the fields of accounting, or auditing and, in any event, do not serve in such capacity. Consequently, it is not the duty of the Committee to plan or conduct financial audits or reserve audits or evaluations, or to determine that the Corporation’s financial statements are complete, accurate and are in accordance with applicable accounting or reserve principles.

This is the responsibility of management and the external auditors and, as to reserves, the external reserve evaluators or auditors. Management and the external auditors will also have the responsibility to conduct investigations and to assure compliance with laws and regulations and the Corporation’s business conduct guidelines.

Composition

The Committee will consist of not less than three directors, all of whom will be independent and will satisfy the financial literacy requirements of securities regulatory requirements.

One of the members of the Committee will be an audit committee financial expert as defined in applicable securities regulatory requirements.

Members of the Committee will be appointed annually at a meeting of the Board, on the recommendation of the Corporate Governance Committee to the Co-Chairs of the Board and will be listed in the annual report to shareholders.

Committee members may be removed or replaced at any time by the Board, and will, in any event, cease to be a member of the Committee upon ceasing to be a member of the Board. Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board.

The Committee Chair will be appointed by the Board, on the recommendation of the Corporate Governance Committee to the Co-Chairs of the Board.

AIF 2016 Page 102

Meetings

The Committee will meet at least four times annually on dates determined by the Chair or at the call of the Chair or any other Committee member, and as many additional times as the Committee deems necessary.

Committee members will strive to be present at all meetings either in person, by telephone or other communications facilities as permit all persons participating in the meeting to hear each other.

A majority of Committee members, present in person, by telephone, or by other permissible communication facilities will constitute a quorum.

The Committee will appoint a secretary, who need not be a member of the Committee, or a director of the Corporation. The secretary will keep minutes of the meetings of the Committee. Minutes will be sent to all Committee members, on a timely basis.

As necessary or desirable, but in any case at least quarterly, the Committee shall meet with members of management and representatives of the external auditors and internal audit in separate executive sessions to discuss any matters that the Committee or any of these groups believes should be discussed privately.

As necessary or desirable, but in any case at least annually, the Committee will meet the management and representatives of the external reserves evaluators or auditors and internal reserves evaluators in separate executive sessions to discuss matters that the Committee or any of these groups believes should be discussed privately.

Authority

Subject to any prior specific directive by the Board, the Committee is granted the authority to investigate any matter or activity involving financial accounting and financial reporting, the internal controls of the Corporation and the reporting of the Corporation’s reserves and oil and gas activities.

The Committee has the authority to engage and set the compensation of independent counsel and other advisors, at the Corporation’s expense, as it determines necessary to carry out its duties.

In recognition of the fact that the external auditors are ultimately accountable to the Committee, the Committee will have the authority and responsibility to recommend to the Board the external auditors that will be proposed for nomination at the annual general meeting. The external auditors will report directly to the Committee, and the Committee will evaluate and, where appropriate, replace the external auditors. The Committee will approve the fees and terms for all audit engagements and all non-audit engagements with the external auditors. The Committee will consult with management and the internal audit group regarding the engagement of the external auditors but will not delegate these responsibilities.

The external qualified reserves evaluators or auditors will report directly to the Committee, and the Committee will evaluate and, where appropriate, replace the external qualified reserves evaluators or auditors. The Committee will approve the fees and terms for all reserves evaluators or audit engagements. The Committee will consult with management and the internal qualified reserves evaluator’s group regarding the engagement of the external qualified reserves evaluators or auditors but will not delegate these responsibilities.

Specific Duties & Responsibilities

The Committee will have the oversight responsibilities and specific duties as described below.

Audit

1. Review and reassess the adequacy of this Mandate annually and recommend any proposed changes to the Corporate Governance Committee and the Board for approval.

2. Review with the Corporation’s management, internal audit and the external auditors and recommend to the Board for approval the Corporation’s annual financial statements and annual MD&A which is to be provided to shareholders and the appropriate regulatory agencies and any financial statement contained in a prospectus, information circular, registration statement or other similar document.

AIF 2016 Page 103

3. Review with the Corporation’s management, internal audit and the external auditors and approve the Corporation’s quarterly financial statements and quarterly MD&A which is to be provided to shareholders and the appropriate regulatory agencies.

4. Review with the Corporation’s management and approve earnings press releases before the Corporation publicly discloses this information.

5. Be responsible for the oversight of the work of the external auditors, including the resolution of disagreements between management of the Corporation and the external auditors regarding financial reporting.

6. Review with the Corporation’s management, internal audit and the external auditors the Corporation’s accounting and financial reporting controls and obtain annually, in writing from the external auditors their observations, if any, on material weaknesses in internal controls over financial reporting as noted during the course of their work.

7. Review with the Corporation’s management, internal audit and the external auditors significant accounting and reporting principles, practices and procedures applied by the Corporation in preparing its financial statements, and discuss with the external auditors their judgments about the quality (not just the acceptability) of the Corporation’s accounting principles used in financial reporting.

8. Review the scope of internal audit’s work plan for the year and receive a summary report of major findings by internal audit and how management is addressing the conditions reported.

9. Review the scope and general extent of the external auditors’ annual audit, such review to include an explanation from the external auditors of the factors considered in determining the audit scope, including the major risk factors, and the external auditor’s confirmation whether or not any limitations have been placed on the scope or nature of their audit procedures.

10. Inquire as to the independence of the external auditors and obtain from the external auditors, at least annually, a formal written statement delineating all relationships between the external auditors and the Corporation as contemplated by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees.

11. Arrange with the external auditors that (a) they will advise the Committee, through its Chair and management of the Corporation, of any matters identified through procedures followed for the review of interim quarterly financial statements of the Corporation, such notification is to be made prior to the related press release and (b), for written confirmation at the end of each of the first three quarters of the year, that they have nothing to report to the Committee, if that is the case, or the written enumeration of required reporting issues.

12. Review at the completion of the annual audit, with senior management, internal audit and the external auditors the following:

i. the annual financial statements and related footnotes and financial information to be included in the Corporation’s annual report to shareholders;

ii. results of the audit of the financial statements and the related report thereon and, if applicable, a report on changes during the year in accounting principles and their application;

iii. significant changes to the audit plan, if any, and any serious disputes or difficulties with management encountered during the audit;

iv. inquire about the cooperation received by the external auditors during their audit, including access to all requested records, data and information; and

v. inquire of the external auditors whether there have been any material disagreements with management, which, if not satisfactorily resolved, would have caused them to issue a non-standard report on the Corporation’s financial statements.

13. Discuss (a) with the external auditors, without management being present, (i) the quality of the Corporation’s financial and accounting personnel, and (ii) the completeness and accuracy of the Corporation’s financial statements, and (b) elicit the comments of senior management regarding the responsiveness of the external auditors to the Corporation’s needs.

14. Meet with management to discuss any relevant significant recommendations that the external auditors may have, particularly those characterized as ‘material’ or ‘serious’ (typically, such recommendations will be presented by the external auditors in the form of a Letter of Comments and Recommendations to the Committee) and review the responses of management to the Letter of Comments and Recommendations and receive follow-up reports on action taken concerning the aforementioned recommendations.

15. Review and approve disclosures required to be included in periodic reports filed with Canadian and U.S. securities regulators with respect to non-audit services performed by the external auditors.

16. Establish adequate procedures for the review of the Corporation’s disclosure of financial information extracted or derived from the Corporation’s financial statements, and periodically assess the adequacy of those procedures.

17. Establish procedures for (a) the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters, and (b) the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters.

AIF 2016 Page 104

18. Review and approve the Corporation’s hiring policies regarding partners, employees and former partners and employees of the present and former external auditors.

19. Review the appointment and replacement of the senior internal audit executive.

20. Review with management, internal audit and the external auditors the methods used to establish and monitor the Corporation’s policies with respect to unethical or illegal activities by the Corporation’s employees that may have a material impact on the financial statements or other reporting of the Corporation.

21. Reviewing generally, as part of the review of the annual financial statements, a report, from the Corporation’s general counsel concerning legal, regulatory and compliance matters that may have a material impact on the financial statements or other reporting of the Corporation.

22. Review and discuss with management, on a regular basis, the identification, management and mitigation of major financial risk exposures across the Corporation. In addition, the Committee oversees the Corporation’s risk management framework and related processes.

Reserves

23. Review, with reasonable frequency, the Corporation’s procedures relating to the disclosure of information with respect to the Corporation’s oil and gas reserves, including the Corporation’s procedures for complying with the disclosure requirements and restrictions of applicable regulatory requirements.

24. Review with management the appointment of the external qualified reserves evaluators or auditors, and in the case of any proposed change in such appointment, determine the reasons for the change and whether there have been disputes between management and the appointed external qualified reserves evaluators or auditors.

25. Review, with reasonable frequency, the Corporation’s procedures for providing information to the external qualified reserves evaluators or auditors who report on reserves and data for the purposes of compliance with applicable securities regulatory requirements.

26. Meet, before the approval and release of the Corporation’s reserves data and the report of the qualified reserve evaluators or auditors thereon, with senior management, the external qualified reserves evaluators or auditors and the internal qualified reserves evaluators to determine whether any restrictions affect their ability to report on reserves data without reservation and to review the reserves data and the report of the qualified reserves evaluators or auditors.

27. Recommend to the Board for approval of the content and filing of required statements and reports relating to the Corporation’s disclosure of reserves data as prescribed by applicable regulatory requirements.

Miscellaneous

28. Review and approve (a) any change or waiver in the Corporation’s Code of Business Conduct for the President and Chief Executive Officer and senior financial officers and (b) any public disclosure made regarding such change or waiver and, if satisfied, refer the matter to the Board for approval.

29. Act in an advisory capacity to the Board.

30. Carry out such other responsibilities as the Board may, from time to time, set forth.

31. Advise and report to the Co-Chairs of the Board and the Board, relative to the duties and responsibilities set out above, from time to time, and in such details as is reasonably appropriate.

Effective Date: May 6, 2014

AIF 2016 Page 105

Schedule B

Husky Energy Inc.

Report on Reserves Data by Internal Qualified Reserves Evaluator

To the Board of Directors of Husky Energy Inc. (“Husky”):

1. Our staff has evaluated Husky’s reserves data as at December 31, 2016. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2016, estimated using forecast prices and costs.

2. The reserves data are the responsibility of Husky’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

3. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”) maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter). Our internal reserves evaluators are not independent of Husky, within the meaning of the term “independent” under those standards.

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

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

Internal Qualified Reserves Evaluator	Effective Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (Before Income Taxes, 10% Discount Rate) Evaluated
Husky	December 31, 2016	Canada	$17,525 million
		China	$4,322 million
		Indonesia	$833 million
			$22,680 million

6. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied.

7. We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our report.

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

9. I have signed this report in my capacity as an employee of Husky and not in my personal capacity.

/s/ Richard Leslie    

Richard Leslie, P. Eng

Manager, Reserves

Calgary, Alberta

January 31, 2017

AIF 2016 Page 106

Schedule C

Husky Energy Inc.

Report of Management and Directors on Oil and Gas Disclosure

Management of Husky Energy Inc. (“Husky”) are responsible for the preparation and disclosure of information with respect to Husky’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2016, estimated using forecast prices and costs.

Husky’s oil and gas reserves evaluation process involves applying generally accepted procedures for the estimation of oil and gas reserves data for the purposes of complying with the legal requirements of NI 51-101. Husky’s Internal Qualified Reserves Evaluator is the Manager of Reserves, who is an employee of Husky and has evaluated Husky’s oil and gas reserves data and certified that Husky’s Reserves Data Process has been followed. The Report on Reserves Data by Husky’s Internal Qualified Reserves Evaluator accompanies this report and will be filed with securities regulatory authorities concurrently with this report.

The Audit Committee of the Board of Directors of Husky has:

a. reviewed Husky’s procedures for providing information to the Internal Qualified Reserves Evaluator and the independent qualified external reserves auditor;

b. met with the Internal Qualified Reserves Evaluator and the independent qualified external reserves auditor to determine whether any restrictions affected the ability of the Internal Qualified Reserves Evaluator or the independent qualified external reserves auditor to report without reservation and, in the event of a proposal to change the independent qualified reserves auditor and evaluator, to inquire whether there had been disputes between the previous independent qualified reserves auditor and evaluator and management; and

c. reviewed the reserves data with management, the Internal Qualified Reserves Evaluator and the independent external reserves auditor.

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

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

b. the filing of Form 51-101F2, which is the Report on Reserves Data of Husky’s Internal Qualified Reserves Evaluator; and

c. the content and filing of this report.

Husky sought and was granted by the Canadian Securities Administrators an exemption from the requirement under National Instrument 51-101 “Standards of Disclosure for Oil and Gas Disclosure” to involve independent qualified oil and gas reserve evaluators or auditors. Notwithstanding this exemption, we involve independent qualified reserve auditors as part of Husky’s corporate governance practices. Their involvement helps assure that our internal oil and gas reserve estimates are materially correct.

In Husky’s view, 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 or independent qualified reserves auditors to evaluate or audit and review the reserves data. The primary factors supporting the involvement of independent qualified reserves evaluators or independent qualified reserves auditors apply when (i) their knowledge of, and experience with, a reporting issuer’s reserves data are superior to that of the internal evaluators; and (ii) the work of the independent qualified reserves evaluator or independent qualified reserves auditors is significantly less likely to be adversely influenced by self-interest or management of the reporting issuer than the work of internal reserves evaluation staff. In Husky’s view, neither of these factors applies in Husky’s circumstances.

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

AIF 2016 Page 107

/s/ Robert J. Peabody	February 24, 2017
Robert J. Peabody President & Chief Executive Officer
/s/ James D. Girgulis	February 24, 2017
James D. Girgulis Senior Vice President, General Counsel & Secretary
/s/ William Shurniak	February 24, 2017
William Shurniak Director
/s/ Frederick S.H. Ma	February 24, 2017
Frederick S.H. Ma Director

AIF 2016 Page 108

Schedule D

Husky Energy Inc.

Independent Engineer’s Audit Opinion

Husky Energy Inc.

707 - 8th Avenue S.W.

Calgary, Alberta

T2P 3G7

Attention: Mr. Richard Leslie, Manager Reserves

Re: Audit of Husky Energy Inc.’s 2016 Year-End Reserves

As requested by Husky Energy Inc. (“Husky” or the “Company”), Sproule has conducted an audit of Husky’s reserves estimates and the respective net present values as at December 31, 2016. Husky internally evaluates all of their properties. Husky’s detailed reserves information was provided to us for this audit. Sproule’s responsibility is to express an independent opinion on the reasonableness of the reserves estimates and the respective net present value estimates, in the aggregate, based on our audit tests and to assess the quality of the Company’s processes and guidelines applied in the preparation of the reserves information.

We conducted our audit in accordance with generally accepted audit standards as recommended by the Society of Petroleum Engineers and the Canadian Oil and Gas Evaluation Handbook (COGEH) Volume 1 Section 12. As part of our audit, Sproule reviewed and assessed the policies, procedures, documentation and guidelines the Company has in place with respect to the estimation, review, documentation, and approval of Husky’s reserves information. The audit included confirming on a test basis that there is adherence on the part of Husky’s internal reserve evaluators and other employees to the reserves management and administration policies and procedures established by the Company. As well, the audit also included conducting reserves evaluation on a sufficient number of the Company’s internally evaluated properties as considered necessary in order to express an opinion.

Based on the results of our audit, it is our opinion 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 COGE Handbook.

The results of the Husky internally generated reserves and net present values (based on forecast prices) supplied to us as part of the audit process are summarized below:

Husky Energy Inc. Internally Evaluated Reserves and Net Present Values Forecast Prices and Costs As of December 31, 2016
	Working Interest Before Royalty Company Share of Remaining Reserves (mmboe)		Company Share of Net Present Value Before Income Tax (MM$) @ 10%
Total Proved		1,224		13,996
Total Proved Plus Probable		2,815		22,680

Sincerely,

Sproule Associates Limited

/s/ Cameron P. Six, P. Eng.    

Cameron P. Six, P. Eng.

Vice-President Engineering, Chief Engineer and

Director

Calgary, Alberta

January 31, 2017

AIF 2016 Page 109

Document B

Form 40-F

Consolidated Financial Statements and

Auditors’ Report to Shareholders

For the Year Ended December 31, 2016

INDEPENDENT AUDITORS’ REPORT OF

REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Husky Energy Inc.

We have audited the accompanying consolidated financial statements of Husky Energy Inc., which comprise the consolidated balance sheets as at December 31, 2016 and December 31, 2015, the consolidated statements of income (loss), comprehensive income (loss), changes in shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Husky Energy Inc. as at December 31, 2016 and December 31, 2015, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Husky Energy Inc.’s internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2017 expressed an unmodified (unqualified) opinion on the effectiveness of Husky Energy Inc.’s internal control over financial reporting.

/s/ KPMG LLP

KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 23, 2017

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Husky Energy Inc.

We have audited Husky Energy Inc.’s (“the Company”) internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Discussion and Analysis. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2016 and December 31, 2015, and the related consolidated statements of income (loss), comprehensive income (loss), changes in shareholders’ equity and cash flows for each of the years then ended, and our report dated February 23, 2017 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 23, 2017

MANAGEMENT’S REPORT

The management of Husky Energy Inc. (“the Company”) is responsible for the financial information and operating data presented in this financial document.

The consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise as they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects. Financial information presented elsewhere in this financial document has been prepared on a basis consistent with that in the consolidated financial statements.

The Company maintains systems of internal accounting and administrative controls. These systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are properly accounted for and adequately safeguarded. Management’s evaluation concluded that the Company’s internal control over financial reporting was effective as of December 31, 2016. The system of internal controls is further supported by an internal audit function.

The Audit Committee of the Board of Directors, composed of independent non-management directors, meets regularly with management, internal auditors as well as the external auditors, to discuss audit (external, internal and joint venture), internal controls, accounting policy and financial reporting matters as well as the reserves determination process. The Committee reviews the annual consolidated financial statements with both management and the independent auditors and reports its findings to the Board of Directors before such statements are approved by the Board. The Committee is also responsible for the appointment of the external auditors for the Company.

The consolidated financial statements have been audited by KPMG LLP, the independent auditors, in accordance with Canadian Auditing Standards and the standards of the Public Company Accounting Oversight Board (United States) on behalf of the shareholders. KPMG LLP has full and free access to the Audit Committee.

“Robert J. Peabody”

Robert J. Peabody

President & Chief Executive Officer

“Jonathan M. McKenzie”

Jonathan M. McKenzie

Chief Financial Officer

Calgary, Canada

February 23, 2017

Consolidated Financial Statements  1

INDEPENDENT AUDITORS’ REPORT

To the Shareholders and Board of Directors of Husky Energy Inc.

We have audited the accompanying consolidated financial statements of Husky Energy Inc., which comprise the consolidated balance sheets as at December 31, 2016 and December 31, 2015, the consolidated statements of income (loss), comprehensive income (loss), changes in shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Husky Energy Inc. as at December 31, 2016 and December 31, 2015, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

“KPMG LLP”

KPMG LLP

Chartered Professional Accountants

February 23, 2017

Calgary, Canada

Consolidated Financial Statements  2

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets

(millions of Canadian dollars)	December 31, 2016		December 31, 2015
Assets
Current assets
Cash and cash equivalents (note 4)		1,319		70
Accounts receivable (notes 5, 24)		1,036		1,014
Income taxes receivable		186		312
Inventories (note 6)		1,558		1,247
Prepaid expenses		135		271
Restricted cash (note 7, 16)		84		—
		4,318		2,914
Restricted cash (note 7, 16)		72		121
Exploration and evaluation assets (note 8)		1,066		1,091
Property, plant and equipment, net (note 9)		24,593		27,634
Goodwill (note 10)		679		700
Investment in joint ventures (note 11)		1,128		359
Long-term income taxes receivable		232		109
Other assets (note 12)		172		128
Total Assets		32,260		33,056
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities (note 14)		2,226		2,527
Short-term debt (note 15)		200		720
Long-term debt due within one year (note 15)		403		277
Contribution payable due within one year (note 11)		146		210
Asset retirement obligations (note 16)		218		102
		3,193		3,836
Long-term debt (note 15)		4,736		5,759
Other long-term liabilities (note 17)		1,020		743
Contribution payable (note 11)		—		138
Asset retirement obligations (note 16)		2,573		2,882
Deferred tax liabilities (note 18)		3,111		3,112
Total Liabilities		14,633		16,470
Shareholders’ equity
Common shares (note 19)		7,296		7,000
Preferred shares (note 19)		874		874
Retained earnings		8,457		7,589
Other reserves		989		1,123
Non-controlling interest		11		—
Total Shareholders’ Equity		17,627		16,586
Total Liabilities and Shareholders’ Equity		32,260		33,056

The accompanying notes to the consolidated financial statements are an integral part of these statements.

On behalf of the Board:

“Robert J. Peabody”	“William Shurniak”
Robert J. Peabody	William Shurniak
Director	Director

Consolidated Financial Statements  3

Consolidated Statements of Income (Loss)

	Year ended December 31,
(millions of Canadian dollars, except share data)	2016			2015
Gross revenues		13,312			16,763
Royalties		(305	)		(432	)
Marketing and other		(88	)		38
Revenues, net of royalties		12,919			16,369
Expenses
Purchases of crude oil and products		7,356			9,397
Production, operating and transportation expenses (note 20)		2,724			2,994
Selling, general and administrative expenses (note 20)		544			342
Depletion, depreciation, amortization and impairment (notes 9, 10)		2,462			8,644
Exploration and evaluation expenses (note 8)		188			447
Gain on sale of assets (note 9)		(1,634	)		(22	)
Other – net		(27	)		(287	)
		11,613			21,515
Earnings (loss) from operating activities		1,306			(5,146	)
Share of equity investment gain (loss) (note 11)		15			(5	)
Financial items (note 21)
Net foreign exchange gains		13			43
Finance income		17			35
Finance expenses		(401	)		(298	)
		(371	)		(220	)
Earnings (loss) before income taxes		950			(5,371	)
Provisions for (recovery of ) income taxes (note 18)
Current		(1	)		306
Deferred		29			(1,827	)
		28			(1,521	)
Net earnings (loss)		922			(3,850	)
Earnings (loss) per share (note 19)
Basic		0.88			(3.95	)
Diluted		0.88			(4.01	)
Weighted average number of common shares outstanding (note 19)
Basic (millions)		1,004.9			984.1
Diluted (millions)		1,004.9			984.1

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Consolidated Financial Statements  4

Consolidated Statements of Comprehensive Income (Loss)

	Year ended December 31,
(millions of Canadian dollars)	2016			2015
Net earnings (loss)		922			(3,850	)
Other comprehensive income (loss)
Items that will not be reclassified into earnings, net of tax:
Remeasurements of pension plans (note 22)		(18	)		(10	)
Items that may be reclassified into earnings, net of tax (note 18):
Derivatives designated as cash flow hedges (note 24)		(2	)		(3	)
Equity investment - share of other comprehensive income		2			—
Exchange differences on translation of foreign operations		(247	)		1,324
Hedge of net investment (note 24)		113			(587	)
Other comprehensive income (loss)		(152	)		724
Comprehensive income (loss)		770			(3,126	)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Consolidated Financial Statements  5

Consolidated Statements of Changes in Shareholders’ Equity

	Attributable to Equity Holders
									Other Reserves
(millions of Canadian dollars)	Common Shares		Preferred Shares			Retained Earnings			Foreign Currency Translation			Hedging			Non- Controlling Interest		Total Shareholders’ Equity
Balance as at December 31, 2014		6,986		534			12,666			366			23			—		20,575
Net loss		—		—			(3,850	)		—			—			—		(3,850	)
Other comprehensive income (loss)
Remeasurements of pension plans (net of tax recovery of $3 million) (note 18, 22)		—		—			(10	)		—			—			—		(10	)
Derivatives designated as cash flow hedges (net of tax recovery of $1 million) (note 18, 24)		—		—			—			—			(3	)		—		(3	)
Exchange differences on translation of foreign operations (net of tax of $215 million) (note 18)		—		—			—			1,324			—			—		1,324
Hedge of net investment (net of tax recovery of $92 million) (note 18, 24)		—		—			—			(587	)		—			—		(587	)
Total comprehensive income (loss)		—		—			(3,860	)		737			(3	)		—		(3,126	)
Transactions with owners recognized directly in equity:
Preferred shares issuance (note 19)		—		350			—			—			—			—		350
Share issue costs (note 19)		—		(10	)		—			—			—			—		(10	)
Stock dividends paid (note 19)		14		—			—			—			—			—		14
Dividends declared on common shares (note 19)		—		—			(1,181	)		—			—			—		(1,181	)
Dividends declared on preferred shares (note 19)		—		—			(36	)		—			—			—		(36	)
Balance as at December 31, 2015		7,000		874			7,589			1,103			20			—		16,586
Net earnings		—		—			922			—			—			—		922
Other comprehensive income (loss)
Remeasurements of pension plans (net of tax recovery of $6 million) (note 18, 22)		—		—			(18	)		—			—			—		(18	)
Derivatives designated as cash flow hedges (net of tax recovery of less than $1 million) (note 18, 24)		—		—			—			—			(2	)		—		(2	)
Equity investment - share of other comprehensive income		—		—			—			—			2			—		2
Exchange differences on translation of foreign operations (net of tax recovery of $40 million) (note 18)		—		—			—			(247	)		—			—		(247	)
Hedge of net investment (net of tax of $17 million) (note 18, 24)		—		—			—			113			—			—		113
Total comprehensive income (loss)		—		—			904			(134	)		—			—		770
Transactions with owners recognized directly in equity:
Stock dividends paid (note 19)		296		—			—			—			—			—		296
Dividends declared on preferred shares (note 19)		—		—			(36	)		—			—			—		(36	)
Non-Controlling Interest in Subsidiary		—		—			—			—			—			11		11
Balance as at December 31, 2016		7,296		874			8,457			969			20			11		17,627

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Consolidated Financial Statements  6

Consolidated Statements of Cash Flows

	Year ended December 31,
(millions of Canadian dollars)	2016			2015
Operating activities
Net earnings (loss)		922			(3,850	)
Items not affecting cash:
Accretion (note 21)		126			121
Depletion, depreciation, amortization and impairment (notes 9, 10)		2,462			8,644
Inventory write-down to net realizable value (note 6)		9			22
Exploration and evaluation expenses (note 8)		86			242
Deferred income taxes (note 18)		29			(1,827	)
Foreign exchange		(4	)		27
Stock-based compensation (note 19, 20)		33			(39	)
Gain on sale of assets (note 9)		(1,634	)		(22	)
Unrealized mark to market		38			(14	)
Other		9			25
Settlement of asset retirement obligations (note 16)		(87	)		(98	)
Deferred revenue (note 17)		209			102
Income taxes received (paid)		3			(227	)
Interest received		5			3
Change in non-cash working capital (note 23)		(235	)		651
Cash flow – operating activities		1,971			3,760
Financing activities
Long-term debt issuance (note 15)		6,181			9,449
Long-term debt repayment (note 15)		(6,949	)		(8,500	)
Short-term debt (note 15)		(520	)		(175	)
Debt issue costs		—			(7	)
Proceeds from preferred share issuance, net of share issue costs (note 19)		—			340
Dividends on common shares (note 19)		—			(1,167	)
Dividends on preferred shares (note 19)		(27	)		(36	)
Interest paid		(349	)		(323	)
Other		21			30
Change in non-cash working capital (note 23)		281			179
Cash flow – financing activities		(1,362	)		(210	)
Investing activities
Capital expenditures		(1,705	)		(3,005	)
Proceeds from asset sales (note 9)		2,935			122
Contribution payable payment (note 11)		(193	)		(1,363	)
Contribution to joint ventures (note 11)		(102	)		(122	)
Other		(30	)		(117	)
Change in non-cash working capital (note 23)		(273	)		(332	)
Cash flow – investing activities		632			(4,817	)
Increase (decrease) in cash and cash equivalents		1,241			(1,267	)
Effect of exchange rates on cash and cash equivalents		8			70
Cash and cash equivalents at beginning of year		70			1,267
Cash and cash equivalents at end of year		1,319			70

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Consolidated Financial Statements  7

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 Description of Business and Segmented Disclosures

Husky Energy Inc. (“Husky” or “the Company”) is an international integrated energy company incorporated under the Business Corporations Act (Alberta). The Company’s common shares are listed on the Toronto Stock Exchange (“TSX”) under the symbol “HSE” and the Cumulative Redeemable Preferred Shares, Series 1, Cumulative Redeemable Preferred Shares, Series 2, Cumulative Redeemable Preferred Shares, Series 3,Cumulative Redeemable Preferred Shares, Series 5 and Cumulative Redeemable Preferred Shares, Series 7 are listed under the symbols, “HSE.PR.A”, “HSE.PR.B”, “HSE.PR.C”, “HSE.PR.E” and “HSE.PR.G”, respectively. The registered office is located at 707, 8th Avenue S.W., PO Box 6525, Station D, Calgary, Alberta, T2P 3G7.

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 natural gas liquids (“NGL”) (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.

Consolidated Financial Statements  8

Segmented Financial Information

	Upstream
($ millions)	Exploration and Production(1)						Infrastructure and Marketing						Total
Year ended December 31,	2016			2015			2016			2015			2016			2015
Gross revenues		4,036			5,374			955			1,264			4,991			6,638
Royalties		(305	)		(432	)		—			—			(305	)		(432	)
Marketing and other		—			—			(88	)		38			(88	)		38
Revenues, net of royalties		3,731			4,942			867			1,302			4,598			6,244
Expenses
Purchases of crude oil and products		32			41			857			1,123			889			1,164
Production, operating and transportation expenses		1,760			2,076			20			37			1,780			2,113
Selling, general and administrative expenses		232			237			5			7			237			244
Depletion, depreciation, amortization and impairment		1,815			7,993			13			25			1,828			8,018
Exploration and evaluation expenses		188			447			—			—			188			447
Gain on sale of assets		(192	)		(17	)		(1,439	)		—			(1,631	)		(17	)
Other – net		53			(34	)		(3	)		(5	)		50			(39	)
		3,888			10,743			(547	)		1,187			3,341			11,930
Earnings (loss) from operating activities		(157	)		(5,801	)		1,414			115			1,257			(5,686	)
Share of equity investment gain (loss)		(1	)		(5	)		16			—			15			(5	)
Financial items
Net foreign exchange gains		—			—			—			—			—			—
Finance income		5			3			—			—			5			3
Finance expenses		(145	)		(142	)		—			—			(145	)		(142	)
		(140	)		(139	)		—			—			(140	)		(139	)
Earnings (loss) before income taxes		(298	)		(5,945	)		1,430			115			1,132			(5,830	)
Provisions for (recovery of ) income taxes
Current		(100	)		(41	)		—			222			(100	)		181
Deferred		19			(1,566	)		122			(191	)		141			(1,757	)
		(81	)		(1,607	)		122			31			41			(1,576	)
Net earnings (loss)		(217	)		(4,338	)		1,308			84			1,091			(4,254	)
Intersegment revenues		988			1,081			—			—			988			1,081

⁽¹⁾  Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production.

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices. Segment results include transactions between business segments.

Consolidated Financial Statements  9

Downstream																								Corporate and Eliminations(2)						Total
Upgrading						Canadian Refined Products						U.S. Refining and Marketing						Total
2016			2015			2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
	1,324			1,319			2,301			2,886			5,995			7,345			9,620			11,550			(1,299	)		(1,425	)		13,312			16,763
	—			—			—			—			—			—			—			—			—			—			(305	)		(432	)
	—			—			—			—			—			—			—			—			—			—			(88	)		38
	1,324			1,319			2,301			2,886			5,995			7,345			9,620			11,550			(1,299	)		(1,425	)		12,919			16,369
	808			922			1,770			2,281			5,188			6,455			7,766			9,658			(1,299	)		(1,425	)		7,356			9,397
	168			169			241			238			535			474			944			881			—			—			2,724			2,994
	4			4			43			31			13			10			60			45			247			53			544			342
	103			106			102			103			342			333			547			542			87			84			2,462			8,644
	—			—			—			—			—			—			—			—			—			—			188			447
	—			—			(3	)		(5	)		—			—			(3	)		(5	)		—			—			(1,634	)		(22	)
	(1	)		(11	)		(10	)		1			(176	)		(236	)		(187	)		(246	)		110			(2	)		(27	)		(287	)
	1,082			1,190			2,143			2,649			5,902			7,036			9,127			10,875			(855	)		(1,290	)		11,613			21,515
	242			129			158			237			93			309			493			675			(444	)		(135	)		1,306			(5,146	)
	—			—			—			—			—			—			—			—			—			—			15			(5	)
	—			—			—			—			—			—			—			—			13			43			13			43
	—			—			—			—			—			—			—			—			12			32			17			35
	(1	)		(1	)		(7	)		(6	)		(3	)		(3	)		(11	)		(10	)		(245	)		(146	)		(401	)		(298	)
	(1	)		(1	)		(7	)		(6	)		(3	)		(3	)		(11	)		(10	)		(220	)		(71	)		(371	)		(220	)
	241			128			151			231			90			306			482			665			(664	)		(206	)		950			(5,371	)
	—			(17	)		—			6			—			15			—			4			99			121			(1	)		306
	66			52			41			55			33			(106	)		140			1			(252	)		(71	)		29			(1,827	)
	66			35			41			61			33			(91	)		140			5			(153	)		50			28			(1,521	)
	175			93			110			170			57			397			342			660			(511	)		(256	)		922			(3,850	)
	157			164			154			180			—			—			311			344			—			—			1,299			1,425

Consolidated Financial Statements  10

Segmented Financial Information

	Upstream
($ millions)	Exploration and Production(1)						Infrastructure and Marketing						Total
Year ended December 31,	2016			2015			2016			2015			2016			2015
Expenditures on exploration and evaluation assets(2)(3)		46			205			—			—			46			205
Expenditures on property, plant and equipment(2)(3)		826			2,064			54			168			880			2,232
Investment in joint ventures		140			37			36			—			176			37
As at December 31,
Exploration and evaluation assets		1,066			1,091			—			—			1,066			1,091
Developing and producing assets at cost		44,790			50,380			—			—			44,790			50,380
Accumulated depletion, depreciation, amortization and impairment		(27,984	)		(31,298	)		—			—			(27,984	)		(31,298	)
Other property, plant and equipment at cost		—			—			140			1,467			140			1,467
Accumulated depletion, depreciation and amortization		—			—			(99	)		(576	)		(99	)		(576	)
Total exploration and evaluation assets and property, plant and equipment, net		17,872			20,173			41			891			17,913			21,064
Total assets		19,098			21,103			1,582			1,699			20,680			22,802

⁽¹⁾  Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production.

⁽²⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the year. Includes assets acquired through acquisitions.

⁽³⁾  Capital expenditures in 2015 were revised to exclude capital expenditures incurred by the Husky-CNOOC Madura Ltd. joint venture which are classified as contribution to joint venture investing activities on the Company’s Consolidated Statements of Cash Flows.

Geographical Financial Information

($ millions)	Canada						United States
Year ended December 31,	2016			2015			2016		2015
Gross revenues(1)		5,993			6,810			6,512		8,638
Royalties		(261	)		(361	)		—		—
Marketing and other		(88	)		38			—		—
Revenue, net of royalties		5,644			6,487			6,512		8,638
As at December 31,
Restricted Cash		—			—			—		—
Exploration and evaluation assets		654			690			—		—
Property, plant and equipment, net		16,112			19,005			5,341		5,139
Goodwill		—			—			679		700
Investment in joint ventures		640			—			—		—
Long-term income tax receivable		232			109			—		—
Other assets		43			83			23		23
Total non-current assets		17,681			19,887			6,043		5,862

⁽¹⁾  Sales to external customers are based on the location of the seller.

Consolidated Financial Statements  11

Downstream																								Corporate and Eliminations						Total
Upgrading						Canadian Refined Products						U.S. Refining and Marketing						Total
2016			2015			2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
	—			—			—			—			—			—			—			—			—			—			46			205
	51			46			52			30			623			425			726			501			53			67			1,659			2,800
	—			—			—			—			—			—			—			—			—			—			176			37
	—			—			—			—			—			—			—			—			—			—			1,066			1,091
	—			—			—			—			—			—			—			—			—			—			44,790			50,380
	—			—			—			—			—			—			—			—			—			—			(27,984	)		(31,298	)
	2,367			2,313			2,500			2,438			7,897			7,435			12,764			12,186			1,011			957			13,915			14,610
	(1,363	)		(1,260	)		(1,344	)		(1,245	)		(2,556	)		(2,296	)		(5,263	)		(4,801	)		(766	)		(681	)		(6,128	)		(6,058	)
	1,004			1,053			1,156			1,193			5,341			5,139			7,501			7,385			245			276			25,659			28,725
	1,076			1,141			1,410			1,448			7,017			6,784			9,503			9,373			2,077			881			32,260			33,056

China						Other International				Total
2016			2015			2016		2015		2016			2015
	807			1,315			—		—		13,312			16,763
	(44	)		(71	)		—		—		(305	)		(432	)
	—			—			—		—		(88	)		38
	763			1,244			—		—		12,919			16,369
	72			121			—		—		72			121
	407			394			5		7		1,066			1,091
	3,139			3,490			1		—		24,593			27,634
	—			—			—		—		679			700
	—			—			488		359		1,128			359
	—			—			—		—		232			109
	83			—			23		22		172			128
	3,701			4,005			517		388		27,942			30,142

Consolidated Financial Statements  12

Note 2 Basis of Presentation

a) Basis of Measurement and Statement of Compliance

The consolidated financial statements have been prepared by management on a historical cost basis with some exceptions, as detailed in the accounting policies set out below in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). These accounting policies have been applied consistently for all periods presented in these consolidated financial statements.

These consolidated financial statements were approved and signed by the Chair of the Audit Committee and the Chief Executive Officer on February 23, 2017 having been duly authorized to do so by the Board of Directors.

Certain prior years’ amounts have been restated to conform with current presentation.

b) Principles of Consolidation

The consolidated financial statements include the accounts of Husky Energy Inc. and its subsidiaries. Subsidiaries are defined as any entities, including unincorporated entities such as partnerships, for which the Company has the power to govern their financial and operating policies to obtain benefits from their activities. Substantially all of the Company’s Upstream activities are conducted jointly with third parties, and accordingly, the accounts reflect the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows from these activities. Intercompany balances, net earnings and unrealized gains and losses arising from intercompany transactions are eliminated in preparing the consolidated financial statements. A portion of the Company’s activities relate to joint ventures (see Note 11), which are accounted for using the equity method.

c) Use of Estimates, Judgments and Assumptions

The timely preparation of the consolidated financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results may differ from these estimates, judgments and assumptions.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and on a prospective basis. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the consolidated financial statements. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Specifically, amounts recorded for depletion, depreciation, amortization and impairment, asset retirement obligations, assets and liabilities measured at fair value, employee future benefits, income taxes and estimates and reserves and contingencies are based on estimates.

Management makes judgments regarding the application of IFRS for each accounting policy. Critical judgments that have the most significant effect on the amounts recognized in the consolidated financial statements include determination of technical feasibility and commercial viability, impairment assessments, the determination of cash generating units (“CGUs”), changes in reserve estimates, the determination of a joint arrangement, the designation of the Company’s functional currency and the fair value of related party transactions.

Significant estimates, judgments and assumptions made by management in the preparation of these consolidated financial statements are outlined in detail in Note 3.

d) Functional and Presentation Currency

The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information is presented in millions of Canadian dollars, except per share amounts and unless otherwise stated.

The designation of the Company’s functional currency is a management judgment based on the currency of the primary economic environment in which the Company operates.

Consolidated Financial Statements  13

Note 3 Significant Accounting Policies

a) Cash and Cash Equivalents

Cash and cash equivalents consist of cash on hand less outstanding cheques and deposits with an original maturity of less than three months at the time of purchase. When outstanding cheques are in excess of cash on hand and short-term deposits, and the Company has the ability to net settle, the excess is reported in bank operating loans.

Cash and cash equivalents held that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within 12 months, it is classified as a non-current asset.

b) Inventories

Crude oil, natural gas, refined petroleum products and sulphur inventories are valued at the lower of cost or net realizable value. Cost is determined using average cost or on a first-in, first-out basis, as appropriate. Materials, parts and supplies are valued at the lower of average cost or net realizable value. Cost consists of raw material, labour, direct overhead, operating costs, transportation and depreciation, depletion and amortization. Commodity inventories held for trading purposes are carried at fair value and measured at fair value less costs to sell based on Level 2 observable inputs, refer to policy Note 3 (m). Any changes in commodity inventory fair value are included as gains or losses in marketing and other in the consolidated statements of income, during the period of change. Previous inventory impairment provisions are reversed when there is a change in the condition that caused the impairment and the inventory remains on hand. Unrealized intersegment net earnings on inventory sales are eliminated.

c) Precious Metals

The Company uses precious metals in conjunction with a catalyst as part of the downstream upgrading and refining processes. These precious metals remain intact; however, there is a loss during the reclamation process. The estimated loss is amortized to production and operating expenses over the period that the precious metal is in use, which is approximately two to five years. After the reclamation process, the actual loss is compared to the estimated loss and any difference is recognized in net earnings. Precious metals are included in other assets on the balance sheet.

d) Exploration and Evaluation Assets and Property, Plant and Equipment

i) Cost

Oil and gas properties and other property, plant and equipment are recorded at cost, including expenditures that are directly attributable to the purchase or development of an asset. Borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset are included in the asset cost. Capitalization ceases when substantially all activities necessary to prepare the qualifying asset for its intended use are complete.

ii) Exploration and evaluation costs

The accounting treatment of costs incurred for oil and natural gas exploration, evaluation and development is determined by the classification of the underlying activities as either exploratory or developmental. The results from an exploration drilling program can take considerable time to analyze, and the determination that commercial reserves have been discovered requires determination of technical feasibility, commercial viability and industry experience. Exploration activities can fluctuate from year to year, due to such factors as the level of exploratory spending, the level of risk sharing with third parties participating in exploratory drilling and the degree of risk associated with drilling in particular areas. Properties that are assumed to be productive may, over a period of time, actually deliver oil and gas in quantities different than originally estimated because of changes in reservoir performance.

Consolidated Financial Statements  14

Costs incurred after the legal right to explore an area has been obtained and before technical feasibility and commercial viability of the area have been established are capitalized as exploration and evaluation assets. These costs include costs to acquire acreage and exploration rights, legal and other professional fees and land brokerage fees. Pre-license costs and geological and geophysical costs associated with exploration activities are expensed in the period incurred. Costs directly associated with an exploration well are initially capitalized as an exploration and evaluation asset until the drilling of the well is complete and the results have been evaluated. If extractable hydrocarbons are found and are likely to be developed commercially, but are subject to further appraisal activity, which may include the drilling of wells, the costs continue to be carried as an exploration and evaluation asset while sufficient and continued progress is made in assessing the commercial viability of the hydrocarbons. Capitalized exploration and evaluation costs or assets are not depreciated and are carried forward until technical feasibility and commercial viability of the area is determined or the assets are determined to be impaired. Management determines technical feasibility and commercial viability when exploration and evaluation assets are reclassified to property, plant and equipment. This decision considers several factors, including the existence of reserves, establishing commercial and technical feasibility and whether the asset can be developed using a proved development concept and has received internal approval. Upon the determination of technical feasibility and commercial viability, capitalized exploration and evaluation assets are then transferred to property, plant and equipment. All such carried costs are subject to technical, commercial and management review, as well as review for impairment indicators, at least every reporting period to confirm the continued intent to develop or otherwise extract value from the discovery. These costs are also tested for impairment when transferred to property, plant and equipment. Capitalized exploration and evaluation expenditures related to wells that do not find reserves, or where no future activity is planned, are expensed as exploration and evaluation expenses.

The application of the Company’s accounting policy for exploration and evaluation costs requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Judgments may change as new information becomes available.

iii) Development costs

Expenditures, including borrowing costs, on the construction, installation and completion of infrastructure facilities, such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, are capitalized as oil and gas properties. Costs incurred to operate and maintain wells and equipment to lift oil and gas to the surface are expensed as production and operating expenses.

iv) Other property, plant and equipment

Repair and maintenance costs, other than major turnaround costs, are expensed as incurred. Major turnaround costs are capitalized as part of property, plant and equipment when incurred and are amortized over the estimated period of time to the anticipated date of the next turnaround.

v) Depletion, depreciation and amortization

Oil and gas properties are depleted on a unit-of-production basis over the proved developed reserves of the particular field, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed reserves of that field, in which case the straight-line method or a unit-of-production method based on total proved plus probable reserves is applied. The unit-of-production rate for the depletion of oil and gas properties related to total proved plus probable reserves takes into account expenditures incurred to date together with sanctioned future development expenditures required to develop the field.

Oil and gas reserves are evaluated internally and audited by independent qualified reserve engineers. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Estimates are based on projected future rates of production, estimated commodity prices, engineering data and the timing of future expenditures, all of which are subject to uncertainty. Changes in reserve estimates can have an impact on reported net earnings through revisions to depletion, depreciation and amortization expense, in addition to determining possible impairments and reversal of impairments of property, plant and equipment.

Net reserves represent the Company’s undivided gross working interest in total reserves after deducting crown, freehold and overriding royalty interests. Assumptions reflect market and regulatory conditions, as applicable, as at the balance sheet date and could differ significantly from other points in time throughout the year or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Depreciation for substantially all other property, plant and equipment is provided using the straight-line method based on the estimated useful lives of assets, which range from five to forty-five years, less any estimated residual value. The useful lives of assets are estimated based upon the period the asset is expected to be available for use by the Company. Residual values are based upon the estimated amount that would be obtained on disposal, net of any costs associated with the disposal. Other property, plant and equipment held under finance leases are depreciated over the shorter of the lease term and the estimated useful life of the asset.

Consolidated Financial Statements  15

Depletion, depreciation and amortization rates for all capitalized costs associated with the Company’s activities are reviewed at least annually, or when events or conditions occur that impact capitalized costs, reserves and estimated service lives.

vi) Finance Leases

Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the Company, are capitalized at the commencement of the lease term at the fair value of the lease property or, if lower, at the present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term.

All other leases are accounted for as operating leases and the lease costs are expensed as incurred.

e) Joint Arrangements

Joint arrangements represent activities where the Company has joint control established by a contractual agreement. Joint control requires unanimous consent for financial and operational decisions. A joint arrangement is either a joint operation, whereby the parties have rights to the assets and obligations for the liabilities, or a joint venture, whereby the parties have rights to the net assets.

For a joint operation, the consolidated financial statements include the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of the joint arrangement. The Company reports items of a similar nature to those on the financial statements of the joint arrangement, on a line-by-line basis, from the date that joint control commences until the date that joint control ceases.

Joint ventures are accounted for using the equity method of accounting and recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the joint venture’s net assets. The Company’s consolidated financial statements include its share of the joint venture’s profit or loss and other comprehensive income (“OCI”) included in investment in joint ventures, until the date that joint control ceases.

Classification of a joint arrangement as either joint operation or joint venture requires judgment. Management’s considerations include, but are not limited to, determining if the arrangement is structured through a separate vehicle and whether the legal form and contractual arrangements give the entity direct rights to the assets and obligations for the liabilities within the normal course of business. Other facts and circumstances are also assessed by management, including the entity’s rights to the economic benefits of assets and its involvement and responsibility for settling liabilities associated with the arrangement.

f) Investments in Associates

An associate is an entity for which the Company has significant influence and thereby has the power to participate in the financial and operational decisions but does not control or jointly control the investee. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the investee’s net assets. The Company’s consolidated financial statements include its share of the investee’s profit or loss and OCI until the date that significant influence ceases.

g) Business Combinations

Business combinations are accounted for using the acquisition method. Determining whether an acquisition meets the definition of a business combination or represents an asset purchase requires judgment on a case-by-case basis. If the acquisition meets the definition of a business combination, the assets and liabilities are recognized based on the contractual terms, economic conditions, the Company’s operating and accounting policies and other factors that exist on the acquisition date, which is the date on which control is transferred to the Company. The identifiable assets and liabilities are measured at their fair values on the acquisition date with limited exceptions. Any additional consideration payable, contingent upon the occurrence of a future event, is recognized at fair value on the acquisition date; subsequent changes in the fair value of the liability are recognized in net earnings. Acquisition costs incurred are expensed and included in other – net in the consolidated statements of income.

Consolidated Financial Statements  16

h) Goodwill

Goodwill is the excess of the purchase price paid over the recognized amount of net assets acquired through business combinations, which is inherently imprecise as judgment is required in the determination of the fair value of assets and liabilities. Goodwill, which is not amortized, is assigned to appropriate CGUs or groups of CGUs. Goodwill is tested for impairment annually and when circumstances indicate that the carrying value may be impaired. Impairment losses are recognized in net earnings and are not subject to reversal. On the disposal or termination of a previously acquired business, any remaining balance of associated goodwill is included in the determination of the gain or loss on disposal.

i) Impairment and Reversals of Impairment on Non-Financial Assets

The carrying amounts of the Company’s non-financial assets, other than inventories and deferred tax assets, are reviewed at the end of each reporting period to determine whether there is an indication of impairment. If such indication exists, the recoverable amount is estimated.

Determining whether there are any indications of impairment or impairment reversals requires significant judgment of external factors, such as an extended decrease in prices or margins for oil and gas commodities or products, a significant decline in an asset’s market value, a significant downward revision of estimated volumes, an upward revision of future development costs, a decline in the entity’s market capitalization or significant changes in the technological, market, economic or legal environment that would have an adverse impact on the Company’s CGUs. If any indication of impairment or impairment reversals exist, an estimate of the asset’s recoverable amount is calculated as the higher of the fair value less costs to sell (“FVLCS”) and the asset’s value in use (“VIU”) for an individual asset or CGU. If the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, the asset is tested as part of a CGU, which is the smallest identifiable group of assets, liabilities and associated goodwill that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Determination of the Company’s CGUs is subject to management’s judgment.

FVLCS is the amount that would be obtained from the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties. The FVLCS is generally determined as the net present value of the estimated future cash flows expected to arise from a CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted using a rate that would be applied by a market participant to arrive at a net present value of the CGU.

VIU is the net present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. VIU is determined by applying assumptions specific to the Company’s continued use and can only take into account sanctioned future development costs. Estimates of future cash flows used in the evaluation of impairment of assets are made using management’s forecasts of commodity prices, operating costs and future capital expenditures, forecasted crack spreads, growth rate, discount rate and, in the case of oil and gas properties, expected production volumes. Expected production volumes take into account assessments of field reservoir performance and include expectations about proved and probable volumes and where applicable economically recoverable resources associated with interests in certain Husky properties which are risk-weighted utilizing geological, production, recovery, market price and economic projections. Either the cash flow estimates or the discount rate is risk-adjusted to reflect local conditions as appropriate.

Given that the calculations for recoverable amounts require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and in the case of oil and gas properties, expected production volumes, it is possible that the assumptions may change, which may impact the estimated life of the CGU and may require a material adjustment to the carrying value of goodwill and non-financial assets.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses recognized with respect to CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the CGU or group of CGUs on a pro rata basis. Impairment losses are recognized in depletion, depreciation, amortization and impairment in the consolidated statements of income (loss).

Impairment losses recognized for other assets in prior years are assessed at the end of each reporting period for indications that the impairment has decreased or no longer exists. An impairment loss is reversed only to the extent that the carrying amount of the asset or CGU does not exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had been recognized.

Consolidated Financial Statements  17

j) Asset Retirement Obligations (“ARO”)

A liability is recognized for future legal or constructive retirement obligations associated with the Company’s assets. The Company has significant obligations to remove tangible assets and restore land after operations cease and the Company retires or relinquishes the asset. The retirement of Upstream and Downstream assets consists primarily of plugging and abandoning wells, abandoning surface and subsea plant and equipment and facilities and restoring land to a state required by regulation or contract. The amount recognized is the net present value of the estimated future expenditures determined in accordance with local conditions, current technology and current regulatory requirements. The obligation is calculated using the current estimated costs to retire the asset inflated to the estimated retirement date and then discounted using a credit-adjusted risk-free discount rate. The liability is recorded in the period in which an obligation arises with a corresponding increase to the carrying value of the related asset. The liability is progressively accreted over time as the effect of discounting unwinds, creating an expense recognized in finance expenses. The costs capitalized to the related assets are amortized in a manner consistent with the depletion, depreciation and amortization of the underlying assets. Actual retirement expenditures are charged against the accumulated liability as incurred.

Liabilities for ARO are adjusted every reporting period for changes in estimates. These adjustments are accounted for as a change in the corresponding capitalized cost, except where a reduction in the provision is greater than the undepreciated capitalized cost of the related assets, in which case the capitalized cost is reduced to nil and the remaining adjustment is recognized in net earnings. Changes to the amount of capitalized costs will result in an adjustment to future depletion, depreciation and amortization, and to finance expenses.

Estimating the ARO requires significant judgment as restoration technologies and costs are constantly changing, as are regulatory, political, environmental and safety considerations. Inherent in the calculation of the ARO are numerous assumptions including the ultimate settlement amounts, future third-party pricing, inflation factors, risk-free discount rates, credit risk, timing of settlement and changes in the legal, regulatory, environmental and political environments. Future revisions to these assumptions may result in material changes to the ARO liability. Adjustments to the estimated amounts and timing of future ARO cash flows are a regular occurrence in light of the significant judgments and estimates involved.

k) Legal and Other Contingent Matters

Provisions and liabilities for legal and other contingent matters are recognized in the period when the circumstance becomes probable that a future cash outflow resulting from past operations or events will occur and the amount of the cash outflow can be reasonably estimated. The timing of recognition and measurement of the provision requires the application of judgment to existing facts and circumstances, which can be subject to change, and the carrying amounts of provisions and liabilities are reviewed regularly and adjusted accordingly. The Company is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations, and determine that the loss can be reasonably estimated. When a loss is recognized, it is charged to net earnings. The Company continually monitors known and potential contingent matters and makes appropriate disclosure and provisions when warranted by the circumstances present.

l) Share Capital

Preferred shares are classified as equity since they are cancellable and redeemable only at the Company’s option and dividends are discretionary and payable only if declared by the Board of Directors. Incremental costs directly attributable to the issuance of shares and stock options are recognized as a deduction from equity, net of tax. Common share dividends are paid out in common shares, or in cash, and preferred share dividends are paid in cash. Both common and preferred share dividends are recognized as distributions within equity.

m) Financial Instruments

Financial instruments are any contracts that give rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial instruments are initially recognized at fair value, and subsequently measured based on classification in one of the following categories: loans and receivables, held to maturity investments, other financial liabilities, fair value through profit or loss (“FVTPL”) or available-for-sale (“AFS”) financial assets.

Financial instruments classified as FVTPL or AFS are measured at fair value at each reporting date; any transaction costs associated with these types of instruments are expensed as incurred. Unrealized gains and losses on AFS financial assets are recognized in OCI (see policy note o) and transferred to net earnings when the asset is derecognized. Unrealized gains and losses on FVTPL financial instruments related to trading activities are recognized in marketing and other in the consolidated statements of income, and unrealized gains and losses on all other FVTPL financial instruments are recognized in other – net.

Consolidated Financial Statements  18

Financial instruments classified as loans or receivables, held to maturity investments and other financial liabilities are initially measured at fair value and subsequently carried at amortized cost using the effective interest rate method. Transaction costs that are directly attributable to the acquisition or issue of a financial instrument are measured at amortized cost and added to the fair value initially recognized.

Financial instruments subsequently revalued at fair value are further categorized using a three-level hierarchy that reflects the significance of the inputs used in determining fair value. Level 1 fair value is determined by reference to quoted prices in active markets for identical assets and liabilities. Level 2 fair value is based on inputs that are independently observable for similar assets or liabilities. Level 3 fair value is not based on independently observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value.

n) Derivative Instruments and Hedging Activities

Derivatives are financial instruments for which the fair value changes in response to market risks, require little or no initial investment and are settled at a future date. Derivative instruments are utilized by the Company to manage various market risks including volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company’s policy is not to utilize derivative instruments for speculative purposes. The Company may enter into swap and other derivative transactions to hedge or mitigate the Company’s commercial risk, including derivatives that reduce risks that arise in the ordinary course of the Company’s business. The Company may choose to apply hedge accounting to derivative instruments.

The fair values of derivatives are determined using valuation models that require assumptions concerning the amount and timing of future cash flows and discount rates. These estimates are also subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance. The actual settlement of a derivative instrument could differ materially from the fair value recorded and could impact future results.

i) Derivative Instruments

All derivative instruments, other than those designated as effective hedging instruments or certain non-financial derivative contracts that meet the Company’s own use requirements, are classified as held for trading and are recorded at fair value. Gains and losses on these instruments are recorded in the consolidated statements of income in the period they occur.

The Company may enter into commodity price contracts in order to offset fixed or floating prices with market rates to manage exposures to fluctuations in commodity prices. The estimation of the fair value of commodity derivatives incorporates forward prices and adjustments for quality or location. The related inventory is measured at fair value based on exit prices. Gains and losses from these derivative contracts, which are not designated as effective hedging instruments, are recognized in revenues or purchases of crude oil and products and are initially recorded at settlement date. Derivative instruments that have been designated as effective hedging instruments are further classified as either fair value or cash flow hedges (see “Hedging Activities”).

ii) Embedded Derivatives

Derivatives embedded in a host contract are recorded separately when the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract and the host contract is not measured at FVTPL. The definition of an embedded derivative is the same as freestanding derivatives. Embedded derivatives are measured at fair value with gains and losses recognized in net earnings.

iii) Hedging Activities

At the inception of a derivative transaction, if the Company elects to use hedge accounting, formal designation and documentation is required. The documentation must include: identification of the hedged item or transaction, the hedging instrument, the nature of the risk being hedged, the Company’s risk management objective and strategy for undertaking the hedge and how the Company will assess the hedging instrument’s effectiveness in offsetting the exposure to changes in the hedged item.

A hedge is assessed at inception and at the end of each reporting period to ensure that it is highly effective in offsetting changes in fair values or cash flows of the hedged item. For a fair value hedge, the gain or loss from remeasuring the hedging instrument at fair value is recognized immediately in net earnings with the offsetting gain or loss on the hedged item. When fair value hedge accounting is discontinued, the carrying amount of the hedging instrument is deferred and amortized to net earnings over the remaining maturity of the hedged item.

For a cash flow hedge, the effective portion of the gain or loss is recorded in OCI. Any hedge or portion of a hedge that is ineffective is immediately recognized in net earnings. Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting. Any gain or loss on the hedging instrument resulting from the discontinuation of a cash flow hedge is deferred in OCI until the forecasted transaction date. If the forecasted transaction date is no longer expected to occur, the gain or loss is recognized in net earnings in the period of discontinuation.

Consolidated Financial Statements  19

A net investment hedge of a foreign operation is accounted for similarly to a cash flow hedge. The Company may designate certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in OCI, net of tax, and are limited to the translation gain or loss on the net investment.

o) Comprehensive Income

Comprehensive income consists of net earnings and OCI. OCI is comprised of the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge or net investment hedge, the unrealized gains and losses on AFS financial assets, the exchange gains and losses arising from the translation of foreign operations with a functional currency that is not Canadian dollars and the actuarial gains and losses on defined benefit pension plans. Amounts included in OCI are shown net of tax. Other reserves is an equity category comprised of the cumulative amounts of OCI, relating to foreign currency translation and hedging.

p) Impairment of Financial Assets

A financial asset is assessed at the end of each reporting period to determine whether it is impaired, based on objective evidence indicating that one or more events have had a negative effect on the estimated future cash flows of that asset. Objective evidence used by the Company to assess impairment of financial assets includes quoted market prices for similar financial assets and historical collection rates for loans and receivables.

An impairment loss with respect to a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the net present value of the estimated future cash flows discounted at the original effective interest rate. A revaluation with respect to an AFS financial asset is calculated by reference to its fair value and any amounts in OCI are transferred to net earnings.

Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

All impairment losses are recognized in net earnings. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized.

Given that the calculations for the net present value of estimated future cash flows related to derivative financial assets require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and expected production volumes, it is possible that the assumptions may change, which may require a material adjustment to the carrying value of financial assets.

q) Pensions and Other Post-employment Benefits

In Canada, the Company provides a defined contribution pension plan and other post-retirement benefits to qualified employees. The Company also maintains a defined benefit pension plan for a small number of employees who did not choose to join the defined contribution pension plan in 1991. In the United States, the Company provides two defined contribution pension plans (401(k)) and one other post-retirement benefits plan.

The cost of the pension benefits earned by employees in the defined contribution pension plans is expensed as incurred. The cost of the benefits earned by employees in the defined benefit pension plans is determined using the projected unit credit funding method. Actuarial gains and losses are recognized in retained earnings as incurred.

The defined benefit asset or liability is comprised of the fair value of plan assets from which the obligations are to be settled and the present value of the defined benefit obligation. Plan assets are measured at fair value based on the closing bid price when there is a quoted price in an active market. Plan assets are assets that are held by a long-term employee benefit fund or qualifying insurance policies. Plan assets are not available to the Company’s creditors. The value of any defined benefit asset is restricted to the sum of any past service costs and the present value of refunds from and reductions in future contributions to the plan. Defined benefit obligations are estimated by discounting expected future payments using the year-end market rate of interest for high-quality corporate debt instruments with cash flows that match the timing and amount of expected benefit payments.

Post-retirement medical benefits are also provided to qualifying retirees. In some cases the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans there is no funding of the benefits before retirement. These plans are recognized on the same basis as described above for the defined benefit pension plan.

Consolidated Financial Statements  20

The determination of the cost of the defined benefit pension plan and the other post-retirement benefit plans reflects a number of assumptions that affect the expected future benefit payments. The valuation of these plans is prepared by an independent actuary engaged by the Company. These assumptions include, but are not limited to, the estimate of expected plan investment performance, salary escalation, retirement age, attrition, future health care costs and mortality. The fair value of the plan assets is used for the purposes of calculating the expected return on plan assets.

The assumptions for each country are reviewed each year and are adjusted where necessary to reflect changes in fund experience and actuarial recommendations. Mortality rates are based on the latest available standard mortality tables for the individual countries concerned. The rate of return on pension plan assets is based on a projection of real long-term bond yields and an equity risk premium, which are combined with local inflation assumptions and applied to the actual asset mix of each plan. The amount of the expected return on plan assets is calculated using the expected rate of return for the year and the fair value of assets at the beginning of the year. Future salary increases are based on expected future inflation rates for the individual countries.

r) Income Taxes

Current income tax is recognized in net earnings in the period unless it relates to items recognized directly to equity, including OCI, in which case the deferred income tax is also recorded in equity. Management periodically evaluates positions taken in the Company’s tax returns with respect to situations in which applicable tax regulations are subject to interpretation and reassessment and establishes provisions where appropriate.

Deferred tax is measured using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

Deferred tax assets and liabilities are recognized at expected tax rates in effect in the year when the asset is expected to be realized or the liability settled, based on tax rates and tax laws that have been enacted or substantively enacted at the reporting date. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs unless it relates to items recognized directly to equity, including OCI, in which case the deferred income tax is also recorded in equity. Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current income tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. Estimates that require significant judgments are also made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where the transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

s) Asset Exchange Transactions

Asset exchange transactions are measured at cost if the transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable. Otherwise, asset exchange transactions are measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. If the acquired item is not measured at fair value, its cost is measured at the carrying amount of the asset given up. Gains and losses are recorded in other – net in the consolidated statements of income in the period they occur.

t) Revenue Recognition

Revenue from the sale of goods is recognized when the significant risks and rewards of ownership have passed to the buyer and it can be reliably measured. Revenues associated with the sale of crude oil, natural gas, natural gas liquids, synthetic crude oil, purchased commodities and refined petroleum products are recognized when the title passes to the customer. Revenues associated with the sale of transportation, processing and natural gas storage services are recognized when the services are provided.

Under take or pay contracts, the Company makes a long-term supply commitment in return for a commitment from the buyer to pay for minimum quantities, whether or not the customer takes delivery. If a buyer has a right to get a “make-up” delivery at a later date, revenue is deferred and recognized only when the product is delivered or the make-up product can no longer be taken. If no such option exists within the contractual terms, revenue is recognized when the take-or-pay penalty is triggered.

Consolidated Financial Statements  21

Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods or services provided in the normal course of business, net of discounts, customs duties and sales taxes. Crude oil and natural gas sold below or above the Company’s working interest share of production results in production underlifts or overlifts. Underlifts are recorded as a receivable at cost with a corresponding decrease to production and operating expense, while overlifts are recorded as a payable at fair value with a corresponding increase to production and operating expense.

Physical exchanges of inventory are reported on a net basis for swaps of similar items, as are sales and purchases made with a common counterparty as part of an arrangement similar to a physical exchange.

Finance income is recognized as the interest accrues using the effective interest rate, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset.

u) Foreign Currency

Functional currency is the currency of the primary economic environment in which the Company and its subsidiaries operate and is normally the currency in which the entity primarily generates and expends cash. The financial statements of Husky’s subsidiaries are translated into Canadian dollars, which is the presentation and functional currency of the Company. The assets and liabilities of subsidiaries whose functional currencies are other than Canadian dollars are translated into Canadian dollars at the foreign exchange rate at the balance sheet date, while revenues and expenses of such subsidiaries are translated using average monthly foreign exchange rates, which approximate the foreign exchange rates on the dates of the transactions. Foreign exchange differences arising on translation are included in OCI.

The Company’s transactions in foreign currencies are translated to the appropriate functional currency at the foreign exchange rate on the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency at the foreign exchange rate at the balance sheet date and differences arising on translation are recognized in net earnings. Non-monetary assets that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the dates of the transactions.

v) Share-based Payments

In accordance with the Company’s stock option plan, stock options to acquire common shares may be granted to officers and certain other employees. The Company records compensation expense over the vesting period based on the fair value of options granted. Compensation expense is recorded in net earnings as part of selling, general and administrative expenses.

The Company’s stock option plan is a tandem plan that provides the stock option holder with the right to exercise the stock option or surrender the option for a cash payment. A liability for the stock options is accrued over their vesting period and measured at fair value using the Black-Scholes option pricing model. The liability is revalued each reporting period until it is settled to reflect changes in the fair value of the options. The net change is recognized in net earnings. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares, consideration paid by the stock option holders and the previously recognized liability associated with the stock options are recorded as share capital.

The Company’s Performance Share Unit Plan provides a time-vested award to certain officers and employees of the Company. Performance Share Units (“PSU”) entitle participants to receive cash based on the Company’s share price at the time of vesting. The amount of cash payment is contingent on the Company’s total shareholder return relative to a peer group of companies and achieving a return on capital in use (“ROCIU”) target. ROCIU equals net earnings plus after tax interest expense divided by the two-year average capital employed, less any capital invested in assets that are not in use. Net earnings is adjusted for the difference between actual realized and budgeted commodity prices and foreign exchange rates and other actual and budgeted exceptional items. A liability for expected cash payments is accrued over the vesting period of the PSUs and is revalued at each reporting date based on the market price of the Company’s common shares and the expected vesting percentage. Upon vesting, a cash payment is made to the participants and the outstanding liability is reduced by the payment amount.

Consolidated Financial Statements  22

w) Earnings per Share

The number of basic common shares outstanding is the weighted average number of common shares outstanding for each period. Shares issued during the period are included in the weighted average number of shares from the date consideration is receivable. The calculation of basic earnings per common share is based on net earnings attributable to common shareholders divided by the weighted average number of common shares outstanding.

The number of diluted common shares outstanding is calculated using the treasury stock method, which assumes that any proceeds received from in-the-money stock options would be used to buy back common shares at the average market price for the period. The calculation of diluted earnings per share is based on net earnings attributable to common shareholders divided by the weighted average number of common shares outstanding adjusted for the effects of all potential dilutive common share issuances, which are comprised of common shares issuable upon exercise of stock options granted to employees. Stock options granted to employees provide the holder with the ability to settle in cash or equity. For the purposes of the diluted earnings per share calculation, the Company must adjust the numerator for the more dilutive effect of cash-settlement versus equity-settlement despite how the stock options are accounted for in net earnings. As a result, net earnings reported based on accounting of cash-settled stock options may be adjusted for the results of equity-settlements for the purposes of determining the numerator for the diluted earnings per share calculation.

x) Government Grants

Government grants are recognized when there is reasonable assurance that the grant will be received and all attached conditions will be complied with. If a grant is received but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until such conditions are fulfilled. When the grant relates to an expense item, it is recognized as income in the period in which the costs are incurred. Where the grant relates to an asset, it is recognized as a reduction to the net book value of the related asset and recognized in net earnings in equal amounts over the expected useful life of the related asset through lower depletion, depreciation and amortization.

y) Related Party Judgments and Estimates

The Company entered into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. These transactions are on terms equivalent to those that prevail in arm’s length transactions, unless otherwise noted. Proceeds for disposition of assets to related parties are recognized at fair value, based on discounted cash flow forecast from those assets. Independent opinions of the fair value may be obtained. Changes in the assumptions used to determine these fair values may result in a material difference in the proceeds and any gain or loss on disposition. See Note 25.

z) Recent Accounting Standards

The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

Leases

In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under the current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the balance sheet, while operating leases are recognized in the Consolidated Statements of Income (Loss) when the expense is incurred. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. The recognition of the present value of minimum lease payments for certain contracts currently classified as operating leases will result in increases to assets, liabilities, depletion, depreciation and amortization, and finance expense, and a decrease to production, operating and transportation expense upon implementation. An optional exemption to not recognize certain short-term leases and leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged. The standard will be effective for annual periods beginning on or after January 1, 2019. Early adoption is permitted, provided IFRS 15 Revenue from Contracts with Customers, has been applied, or is applied at the same date as IFRS 16. The Company is currently evaluating the dollar impact of adopting IFRS 16 on the Company’s consolidated financial statements.

Revenue from Contracts with Customers

In September 2015, the IASB published an amendment to IFRS 15, deferring the effective date of the standard by one year to annual periods beginning on or after January 1, 2018. IFRS 15 replaces existing revenue recognition guidance with a single comprehensive accounting model. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Early adoption is permitted. The Company is currently in the scoping phase of implementation. Adopting IFRS 15 is not expected to have a material impact on the Company’s consolidated financial statements.

Consolidated Financial Statements  23

Financial Instruments

In July 2014, the IASB issued IFRS 9, “Financial Instruments” to replace IAS 39, which provides a single model for classification and measurement based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial instruments. For financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. IFRS 9 includes a new, forward-looking ‘expected loss’ impairment model that will result in more timely recognition of expected credit losses. In addition, IFRS 9 provides a substantially-reformed approach to hedge accounting. The standard is effective for annual periods beginning on or after January 1, 2018, with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt the standard on January 1, 2018. The adoption of IFRS 9 is not expected to have a material impact on the Company’s consolidated financial statements.

Amendments to IAS 7 Statement of Cash Flows

In January 2016, the IASB issued amendments to IAS 7 to be applied prospectively for annual periods beginning on or after January

1, 2017 with early adoption permitted. The amendments require disclosure of information enabling users of financial statements to evaluate changes in liabilities arising from financing activities. The adoption of the IAS 7 amendments will require additional disclosure in the Company’s consolidated financial statements.

Amendments to IFRS 2 Share-based Payment

In June 2016, the IASB issued amendments to IFRS 2 to be applied prospectively for annual periods beginning on or after January 1, 2018 with early adoption permitted. The amendments clarify how to account for certain types of share-based payment transactions. The adoption of the amendments is not expected to have a material impact on the Company’s consolidated financial statements.

aa) Change in Accounting Policy

The Company has applied the following amendments to accounting standards issued by the IASB for the first time for the annual reporting period commencing January 1, 2016:

Amendments to IAS 1 Presentation of Financial Statements

The amendments clarify guidance on materiality and aggregation, use of subtotals, aggregation and disaggregation of financial statement line items, the order of the notes to the financial statements and disclosure of significant accounting policies. The adoption of this amended standard had no material impact on the Company’s consolidated financial statements.

Amendments to IFRS 7 Financial Instrument: Disclosures

The amendments clarify:

• Whether a servicing contract is continuing involvement in a transferred asset for the purpose of determining the disclosures required; and

• The applicability of the amendments to IFRS 7 on offsetting disclosures to condensed interim financial statements.

The adoption of this amended standard had no material impact on the Company’s consolidated financial statements.

Consolidated Financial Statements  24

Note 4 Cash and Cash Equivalents

Cash and cash equivalents at December 31, 2016 included $271 million of cash (December 31, 2015 – $68 million) and $1,048 million of short-term investments with original maturities less than three months at the time of purchase (December 31, 2015 – $2 million ).

Note 5 Accounts Receivable

Accounts Receivable

($ millions)	December 31, 2016			December 31, 2015
Trade receivables		1,019			962
Allowance for doubtful accounts		(32	)		(31	)
Derivatives due within one year		9			59
Other		40			24
End of year		1,036			1,014

Note 6 Inventories

Inventories

($ millions)	December 31, 2016		December 31, 2015
Crude oil, natural gas and sulphur		523		536
Refined petroleum products		433		257
Trading inventories measured at fair value less costs to sell		399		257
Materials, supplies and other		203		197
End of year		1,558		1,247

Impairment of inventory to net realizable value for the year ended December 31, 2016 was $9 million (December 31, 2015 – $22 million).

Trading inventories measured at fair value less costs to sell consist of natural gas inventories and crude oil inventories. The fair value measurement incorporates exit commodity prices and adjustments for quality and location. Refer to Note 24.

Note 7 Restricted Cash

In accordance with the provisions of the regulations of the People’s Republic of China, the Company is required to deposit funds into separate accounts restricted to the funding of future asset retirement obligations in the Asia Pacific Region. As at December 31, 2016, the Company had deposited funds of $156 million (2015 – $121 million) into the restricted cash account, of which $84 million relates to the Wenchang field and have been classified as current and the remaining balance of $72 million have been classified as non-current.

Consolidated Financial Statements  25

Note 8 Exploration and Evaluation Costs

Exploration and Evaluation Assets

($ millions)	2016			2015
Beginning of year		1,091			1,149
Additions		95			227
Disposals		(6	)		—
Transfers to oil and gas properties (note 9)		(18	)		(97	)
Expensed exploration expenditures previously capitalized		(86	)		(242	)
Exchange adjustments		(10	)		54
End of year		1,066			1,091

During 2016, the $86 million in expensed exploration expenditures previously capitalized primarily relates to two unsuccessful exploration wells in the Atlantic Region and a decision by management to not pursue further evaluation of certain Oil Sands assets at this time, due to them being uneconomic under current and long term commodity prices.

The following exploration and evaluation expenses for the years ended December 31, 2016 and 2015 relate to activities associated with the exploration for and evaluation of crude oil and natural gas resources and were recorded in the Upstream Exploration and Production business.

Exploration and Evaluation Expense Summary

($ millions)	2016		2015
Seismic, geological and geophysical		78		103
Expensed drilling		66		297
Expensed land		44		47
		188		447

During 2015, $48 million of the $297 million in total expensed drilling was recorded as an exploration and evaluation expense due to unfulfilled work commitment penalties in Western Canada resulting from management’s plan to withdraw from further exploration and evaluation due to lower estimated short and long-term crude oil and natural gas prices.

Consolidated Financial Statements  26

Note 9 Property, Plant and Equipment

Property, Plant and Equipment

($ millions)	Oil and Gas Properties			Processing, Transportation and Storage			Upgrading			Refining			Retail and Other			Total
Cost
December 31, 2014		47,974			1,296			2,274			6,561			2,632			60,737
Additions		2,128			173			46			452			76			2,875
Acquisitions		57			—			—			—			—			57
Transfers from exploration and evaluation (note 8)		97			—			—			—			—			97
Intersegment transfers		6			(6	)		—			—			—			—
Changes in asset retirement obligations (note 16)		(107	)		—			(7	)		(5	)		(18	)		(137	)
Disposals and derecognition		(487	)		—			—			(24	)		(4	)		(515	)
Exchange adjustments		720			2			—			1,152			2			1,876
December 31, 2015		50,388			1,465			2,313			8,136			2,688			64,990
Additions		818			55			51			712			61			1,697
Acquisitions		67			—			—			—			—			67
Transfers from exploration and evaluation (note 8)		18			—			—			—			—			18
Changes in asset retirement obligations (note 16)		231			—			3			11			9			254
Disposals and derecognition		(6,590	)		(1,383	)		—			—			(3	)		(7,976	)
Exchange adjustments		(131	)		—			—			(214	)		—			(345	)
December 31, 2016		44,801			137			2,367			8,645			2,755			58,705
Accumulated depletion, depreciation, amortization and impairment
December 31, 2014		(23,687	)		(527	)		(1,154	)		(1,988	)		(1,394	)		(28,750	)
Depletion, depreciation, amortization and impairment		(7,811	)		(48	)		(106	)		(365	)		(154	)		(8,484	)
Intersegment transfers		(2	)		2			—			—			—			—
Disposals and derecognition		370			—			—			18			2			390
Exchange adjustments		(170	)		(1	)		—			(341	)		—			(512	)
December 31, 2015		(31,300	)		(574	)		(1,260	)		(2,676	)		(1,546	)		(37,356	)
Depletion, depreciation, amortization and impairment		(1,806	)		(23	)		(103	)		(380	)		(150	)		(2,462	)
Disposals and derecognition		5,082			501			—			13			4			5,600
Exchange adjustments		38			—			—			68			—			106
December 31, 2016		(27,986	)		(96	)		(1,363	)		(2,975	)		(1,692	)		(34,112	)
Net book value
December 31, 2015		19,088			891			1,053			5,460			1,142			27,634
December 31, 2016		16,815			41			1,004			5,670			1,063			24,593

Included in depletion, depreciation, amortization and impairment expense for the year ended December 31, 2016 is a pre-tax net impairment reversal of $261 million (2015 - pre-tax impairment expense of $5,021 million) on crude oil and natural gas assets located in Western Canada in the Upstream Exploration and Production segment.

Under IFRS, any asset impairment that is recorded must be reversed to its original value less any associated depletion, depreciation and amortization expenses should there be indicators that the recoverable amount of the asset has increased in value since the time of recognizing the initial impairment. At December 31, 2016, a $336 million pre-tax recovery of impairment was recognized on the Rainbow CGU in the Upstream Exploration and Production segment, due to acceleration of production profiles and revised operational economics, based on recent production performance and reinforced by market transactions. The recoverable amount for the Rainbow CGU as at December 31, 2016 is $604 million (2015 - $346 million). The recoverable amount of the CGU was estimated based on FVLCS using estimated discounted cash flows based on proved plus probable reserves and a pre-tax discount rate of 11 percent (Level 3). The Company did not identify any further impairment reversal indicators across the other CGUs.

Consolidated Financial Statements  27

The pre-tax impairment expense of $58 million (2015 - $101 million) for the year ended December 31, 2016 related to crude oil and natural gas assets located in the Provost West CGU. The impairment charge within the Upstream Exploration and Production segment, reflected in the fourth quarter of 2016, was the result of negative technical reserve revisions based on recent production performance and reinforced by market transactions. The recoverable amount for the Provost West CGU as at December 31, 2016 is $10 million (2015 - $91 million). The recoverable amount is based on FVLCS using estimated discounted cash flows based on proved plus probable reserves and a pre-tax discount rate of 11 percent (Level 3). In addition, an impairment of $17 million was recorded on the Northern CGU prior to sale (Level 3). The Company did not identify any further impairment indicators across the other CGUs.

The recoverable amount is sensitive to commodity price, discount rate, production volumes, operating costs, royalty rates and future capital expenditures. Commodity prices are based on market indicators at the end of the period. Management’s long-term assumptions are benchmarked against the forward price curve and external firms. The prices used are consistent with those used by the Company in determining the recoverable amount of property, plant and equipment. The discount rate for FVLCS represents the rate a market participant would apply to the cash flows in a market transaction. Production volumes, operating costs and future capital expenditures are based on management’s best estimates of future costs included in the long range plan approved by the Board of Directors.

A change in the discount rate or forward price over the life of the reserves will result in the following impact on the Provost West and Rainbow CGUs:

	Discount Rate						Commodity Price
($ millions)	1% Increase in Discount Rate			1% Decrease in Discount Rate			5% Increase in Forward Price			5% Decrease in Forward Price
Impairment of PP&E, Provost West - Increase (Decrease)		2			(2	)		(12	)		11
Impairment Reversal of PP&E, Rainbow - Increase (Decrease)		(25	)		26			95			(95	)

The table below summarizes the forecasted prices used in determining the recoverable amounts in the above CGUs:

	WTI ($US/bbl)		Brent ($US/bbl)		Edmonton Light ($CDN/bbl)		AECO ($CDN/mcf)		Foreign Exchange ($US/$CDN)
2017		55.00		60.00		64.94		3.06		0.770
2018		60.00		70.00		74.88		3.12		0.800
2019		65.00		71.40		76.37		3.18		0.800
2020		70.00		72.83		77.90		3.25		0.800
2021		71.40		74.28		79.46		3.31		0.800
2022		72.83		75.77		81.05		3.38		0.800
2023(1)		74.28		77.29		82.67		3.45		0.800

⁽¹⁾ Prices are escalated at 2 percent thereafter.

Costs of property, plant and equipment, including major development projects, not subject to depletion, depreciation and amortization as at December 31, 2016 were $1.8 billion (December 31, 2015 – $3.0 billion) including undeveloped land assets of $95 million as at December 31, 2016 (December 31, 2015 – $68 million).

The net book values of assets held under finance lease within property, plant and equipment are as follows:

Assets Under Finance Lease

($ millions)	Refining		Oil and Gas Properties		Total
December 31, 2015		26		255		281
December 31, 2016		24		255		279

Consolidated Financial Statements  28

Assets Dispositions

On May 25, 2016, the Company completed the sale of royalty interests representing approximately 1,700 boe/day of Western Canada production for gross proceeds of $165 million, resulting in a pre-tax gain of $163 million and an after-tax gain of $119 million.

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 Company also recognized an investment of $621 million for its 35 percent retained interest. This transaction resulted in a change of control and the recognition of a pre-tax gain of $1.44 billion and an after-tax gain of $1.32 billion. The assets and related liabilities were recorded in the Upstream Infrastructure and Marketing segment. The assets are held by a newly formed limited partnership, Husky Midstream Limited Partnership (“HMLP”), of which the Company owns 35 percent, Power Assets Holding Ltd. (“PAH”) owns 48.75 percent and Cheung Kong Infrastructure Holdings Ltd. (“CKI”) owns 16.25 percent. Husky remains operator of the assets.

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. The Company recognized a pre-tax gain of $35 million and an after-tax gain of $25 million.

Note 10 Goodwill

Goodwill

($ millions)	December 31, 2016			December 31, 2015
Beginning of year		700			746
Exchange adjustments		(21	)		114
Impairment		—			(160	)
End of year		679			700

As at December 31, 2016, the Company’s goodwill balance related entirely to the Lima Refinery. For impairment testing purposes, the recoverable amount of the Lima Refinery CGU was estimated using the higher of FVLCS and VIU methodology based on cash flows expected over a 50-year period and discounted using a pre-tax discount rate of 8 percent (2015 – 8 percent).

The value-in-use calculation for the Lima Refinery CGU is sensitive to changes in discount rate, forecasted crack spreads and growth rate. The discount rate is derived from the Company’s post-tax weighted average cost of capital with appropriate adjustments made to reflect the risks specific to the refinery. Forecasted crack spreads are based on quoted near-month contracts for WTI and spot prices for gasoline and diesel, and are consistent with crack spreads used in the Company’s long range plan.

Cash flow projections for the initial 10-year period are based on long range plan future cash flows and inflated by a 2 percent long-term growth rate for the remaining 40-year period. The inflation rate was based upon an average expected inflation rate for the U.S. of 2 percent (2015 – 2 percent). As at December 31, 2016, the recoverable amount exceeded the carrying amount and no impairment was identified.

The Company used the market capitalization and comparative market multiplier to corroborate discounted cash flow results.

Consolidated Financial Statements  29

Note 11 Joint Arrangements

Joint Operations

BP-Husky Refining LLC

The Company holds a 50 percent ownership interest in BP-Husky Refining LLC, which owns and operates the BP-Husky Toledo Refinery in Ohio. On March 31, 2008, the Company completed a transaction with BP whereby BP contributed the BP-Husky Toledo Refinery plus inventories and other related net assets and the Company contributed U.S. $250 million in cash and a contribution payable of U.S. $2.6 billion.

The Company’s proportionate share of the contribution payable included in the consolidated balance sheets is as follows:

Contribution Payable

($ millions)	December 31, 2016			December 31, 2015
Beginning of year		348			1,528
Accretion (note 21)		6			16
Paid		(193	)		(1,363	)
Foreign exchange		(15	)		167
End of year		146			348
Expected to be incurred within 1 year		146			210
Expected to be incurred beyond 1 year		—			138

The Company amended the terms of payment of the Company’s contribution payable with BP-Husky Refining LLC in the first quarter of 2015. In accordance with the amendment, U.S. $1 billion of the net contribution payable was paid on February 2, 2015. Subsequent to the payment, BP-Husky Refining LLC distributed U.S. $1 billion to each of the joint arrangement partners, which resulted in the creation of a deferred tax asset and deferred tax recovery of $203 million. As a result of prepayment, the accretion rate was reduced from 6 percent to 2.5 percent for the future term of the agreement and the remaining maturity date was extended to December 31, 2017. The remaining net contribution payable amount of approximately U.S. $110 million (CDN $146 million) will be paid by way of funding all capital contributions of the BP-Husky Refining LLC joint operation during 2017 and repaying the remaining balance by the end of 2017.

Summarized below is the Company’s proportionate share of operating results and financial position in the BP-Husky Refining LLC joint operation that have been included in the consolidated statements of income (loss) and the consolidated balance sheets in U.S. Refining and Marketing in the Downstream segment:

Results of Operations

($ millions)	2016			2015
Revenues		1,521			1,959
Expenses		(1,570	)		(1,826	)
Proportionate share of net earnings (loss)		(49	)		133

Balance Sheets

($ millions)	December 31, 2016			December 31, 2015
Current assets		395			469
Non-current assets		2,446			2,405
Current liabilities		(324	)		(367	)
Non-current liabilities		(535	)		(681	)
Proportionate share of net assets		1,982			1,826

Consolidated Financial Statements  30

Sunrise Oil Sands Partnership

The Company holds a 50 percent interest in the Sunrise Oil Sands Partnership, which is engaged in operating an oil sands project in Northern Alberta.

Summarized below is the Company’s proportionate share of operating results and financial position in the Sunrise Oil Sands Partnership that have been included in the consolidated statements of income (loss) and the consolidated balance sheets in Exploration and Production in the Upstream segment:

Results of Operations

($ millions)	2016			2015
Revenues		106			17
Expenses		(220	)		(160	)
Financial items		(28	)		(28	)
Proportionate share of net loss		(142	)		(171	)

Balance Sheets

($ millions)	December 31, 2016			December 31, 2015
Current assets		57			28
Non-current assets		3,147			3,161
Current liabilities		(98	)		(104	)
Non-current liabilities		(274	)		(248	)
Proportionate share of net assets		2,832			2,837

Joint Venture

Husky-CNOOC Madura Ltd.

The Company currently holds 40 percent joint control in Husky-CNOOC Madura Ltd., which is engaged in exploring for oil and gas resources in Indonesia with a fiscal year end of December 31. Results of the joint venture are included in the consolidated statements of income (loss) in Exploration and Production in the Upstream segment.

Summarized below is the financial information for Husky-CNOOC Madura Ltd. accounted for using the equity method:

Results of Operations

($ millions, except share of equity investment)	2016			2015
Revenues		—			—
Expenses		(32	)		(25	)
Net loss		(32	)		(25	)
Share of equity investment (percent)		40	%		40	%
Proportionate share of equity investment		(1	)		(5	)

Balance Sheets

($ millions, except share of equity investment)	December 31, 2016			December 31, 2015
Current assets(1)		67			79
Non-current assets		1,111			780
Current liabilities		(134	)		(46	)
Non-current liabilities		(836	)		(559	)
Net assets		208			254
Share of net assets (percent)		40	%		40	%
Carrying amount in balance sheet		488			359

⁽¹⁾ Current assets include cash and cash equivalents of $7 million (2015 – $34 million).

Consolidated Financial Statements  31

The Company’s share of equity investment and carrying amount of share of net assets does not equal the 40 percent joint control of the expenses and net assets of Husky-CNOOC Madura Ltd. due to differences in the accounting policies of the joint venture and the Company and non-current liabilities of the joint venture which are not included in the Company’s carrying amount of net assets due to equity accounting.

Husky Midstream Limited Partnership

On July 15, 2016, the Company completed the sale of its ownership interest in select midstream assets in the Lloydminster region of Alberta and Saskatchewan. The assets are held by a newly-formed limited partnership, HMLP, of which Husky owns 35 percent, PAH owns 48.75 percent and CKI owns 16.25 percent. Results of the joint venture are included in the Upstream Infrastructure and Marketing segment.

Summarized below is the financial information for HMLP accounted for using the equity method:

Results of Operations

($ millions, except share of equity investment)	2016
Revenues		138
Expenses(1)		(97	)
Net income		41
Share of equity investment (percent)		35	%
Proportionate share of equity investment		16

Balance Sheet

($ millions, except share of net assets)	December 31, 2016
Current assets(2)		55
Non-current assets		2,403
Current liabilities		(44	)
Non-current liabilities		(590	)
Net assets		1,824
Share of net assets (percent)		35	%
Carrying amount in balance sheet		640

⁽¹⁾ As at December 31, 2016, total gross costs incurred in response to the pipeline leak were approximately $107 million, for which $88 million has been recovered through insurance proceeds. Both the spill costs and insurance recoveries have been incurred by HMLP.

⁽²⁾ Current assets include cash and cash equivalents of $23 million.

The Company’s share of equity investment and carrying amount of share of net assets does not equal the 35 percent joint control of the net income and net assets of HMLP due to the potential fluctuation in the partnership profit structure.

Consolidated Financial Statements  32

Note 12 Other Assets

Other Assets

($ millions)	December 31, 2016		December 31, 2015
Long-term receivables		117		33
Leasehold incentives		13		34
Precious metals		23		23
Other		19		38
End of period		172		128

Note 13 Bank Operating Loans

At December 31, 2016, the Company had unsecured short-term borrowing lines of credit with banks totalling $670 million (December 31, 2015 – $645 million) and letters of credit under these lines of credit totalling $378 million (December 31, 2015 – $216 million). As at December 31, 2016, bank operating loans were nil (December 31, 2015 – nil). Interest payable is based on Bankers’ Acceptance, U.S. LIBOR or prime rates.

The Sunrise Oil Sands Partnership has an unsecured demand credit facility of $10 million (December 31, 2015 - $10 million) available for general purposes. The Company’s proportionate share of the liability for any drawings under this credit facility is $5 million (December 31, 2015 - $5 million). As at December 31, 2016, there was no balance outstanding under this credit facility (December 31, 2015 – nil).

Note 14 Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities

($ millions)	December 31, 2016		December 31, 2015
Trade payables		762		636
Accrued liabilities		1,275		1,498
Dividend payable (note 19)		9		296
Stock-based compensation		17		6
Derivatives due within one year		61		18
Other		102		73
End of year		2,226		2,527

Consolidated Financial Statements  33

Note 15 Debt and Credit Facilities

Short-term Debt

($ millions)	December 31, 2016		December 31, 2015
Commercial paper(1)		200		720

⁽¹⁾  The commercial paper 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. The weighted average interest rate as at December 31, 2016 was 0.93 percent per annum (December 31, 2015 – 0.81 percent).

			Canadian $ Amount						U.S. $ Denominated
Long-term Debt			December 31,			December 31,			December 31,		December 31,
($ millions)	Maturity		2016			2015			2016		2015
Long-term debt
Syndicated Credit Facility		2018		—			499			—		—
6.20% notes(1)(5)		2017		—			415			—		300
6.15% notes(1)(4)		2019		403			415			300		300
7.25% notes(1)(5)		2019		1,007			1,038			750		750
5.00% notes(6)		2020		400			400			—		—
3.95% notes(1)(5)		2022		671			692			500		500
4.00% notes (1)(5)		2024		1,007			1,038			750		750
3.55% notes(6)		2025		750			750			—		—
6.80% notes(1)(5)		2037		519			535			387		387
Debt issue costs(2)				(23	)		(27	)		—		—
Unwound interest rate swaps (note 24)				2			4			—		—
Long-term debt				4,736			5,759			2,687		2,987
Long-term debt due within one year
7.55% notes(1)(3)		2016		—			277			—		200
6.20% notes(1)(5)		2017		403			—			300		—
Long-term debt due within one year				403			277			300		200

⁽¹⁾ All of the Company’s U.S. denominated debt is designated as a hedge of the Company’s net investment in its U.S. refining operations. Refer to Note 24 for foreign exchange risk management through hedge of net investment.

⁽²⁾ Calculated using the effective interest rate method.

⁽³⁾ The 7.55% notes represent unsecured securities under a trust indenture dated October 31, 1996.

⁽⁴⁾ The 6.15% notes represent unsecured securities under a trust indenture dated June 14, 2002.

⁽⁵⁾ The 6.20%, the 7.25%, the 3.95%, the 4.00% and the 6.80% notes represent unsecured securities under a trust indenture dated September 11, 2007.

⁽⁶⁾ The 5.00% and the 3.55% notes represents unsecured securities under a trust indenture dated December 21, 2009.

During the year ended December 31, 2016, the Company had net cumulative long-term debt repayments of $768 million (2015 - net cumulative long-term debt issuance of $949 million) towards the Company’s syndicated credit facilities and long-term debt.

Credit Facilities

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 under both of its revolving syndicated credit facilities was modified to a debt to capital covenant calculated as total debt (long-term debt including long-term debt due within one year and short-term debt) and certain adjusting items specified in the agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the agreement. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2016 and assesses the risk of non-compliance to be low. As at December 31, 2016, the Company had no borrowings under its $2.0 billion facility expiring March 9, 2020 and no borrowings under its $2.0 billion facility expiring June 19, 2018 (December 31, 2015 - $499 million).

There continues to be no difference between the terms of these facilities, other than their maturity dates. Interest rates vary based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected and credit ratings assigned by certain credit rating agencies to the Company’s rated senior unsecured debt.

Consolidated Financial Statements  34

Notes

On February 23, 2015, the Company filed a universal short form base shelf prospectus with applicable securities regulators in each of the provinces of Canada (the “Canadian Shelf Prospectus”) that 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. During the 25-month period that the Canadian Shelf Prospectus is effective, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement.

On March 12, 2015, the Company repaid the maturing 3.75 percent 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. Net proceeds from the offering was used for general corporate purposes, which included, among other things, the partial repayment of bank debt incurred by the Company to fund early payment of U.S. $1 billion of the Company’s net capital contribution payable with BP-Husky Refining LLC.

On December 22, 2015, the Company filed a universal short form base shelf prospectus (the “U.S. Shelf Prospectus”) with the Alberta Securities Commission and a related U.S. registration statement containing the U.S. Shelf Prospectus with the SEC that 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 United States up to and including January 22, 2018. During the 25-month period that the U.S. Shelf Prospectus and the related U.S registration statement are effective, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement.

On November 15, 2016, the Company repaid the 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.

At December 31, 2016, the Company had unused capacity of $1.9 billion under its Canadian Shelf Prospectus and U.S. $3.0 billion under its U.S. Shelf Prospectus and related U.S. registration statement.

The Company’s notes, credit facilities and short-term lines of credit rank equally in right of payment.

Note 16 Asset Retirement Obligations

At December 31, 2016, the estimated total undiscounted inflation-adjusted amount required to settle the Company’s ARO was $11.4 billion (December 31, 2015 – $13.9 billion). These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 41 years into the future. This amount has been discounted using credit-adjusted risk-free rates of 2.8 percent to 5.3 percent (December 31, 2015 – 2.7 percent to 5.8 percent) and an inflation rate of 2 percent (December 31, 2015 – 2 percent). Obligations related to future environmental remediation and cleanup of oil and gas assets are included in the estimated ARO. The Company had deposited funds of $156 million (2015 – $121 million) into the restricted cash account, of which $84 million relates to the Wenchang field and have been classified as current and the remaining balance of $72 million have been classified as non-current.

The change in the provision in 2016 is primarily due to the disposition of select legacy Western Canada crude oil and natural gas assets in 2016.

While the provision is based on management’s best estimates of future costs, discount rates and the economic lives of the assets, there is uncertainty regarding the amount and timing of incurring these costs.

Consolidated Financial Statements  35

A reconciliation of the carrying amount of asset retirement obligations at December 31, 2016 and 2015 is set out below:

Asset Retirement Obligations

($ millions)	2016			2015
Beginning of year		2,984			3,065
Additions		16			23
Liabilities settled		(87	)		(98	)
Liabilities disposed		(452	)		(19	)
Change in discount rate		205			(500	)
Change in estimates		25			340
Exchange adjustment		(26	)		52
Accretion (note 21)		126			121
End of year		2,791			2,984
Expected to be incurred within 1 year		218			102
Expected to be incurred beyond 1 year		2,573			2,882

Note 17 Other Long-term Liabilities

Other Long-term Liabilities

($ millions)	December 31, 2016		December 31, 2015
Employee future benefits (note 22)		208		176
Finance lease obligations		288		266
Stock-based compensation		14		12
Deferred revenue		321		109
Leasehold incentives		104		104
Other		85		76
End of year		1,020		743

Finance lease obligations

The Company, on behalf of the Sunrise Oil Sands Partnership, entered into an arrangement for the construction and use of pipeline and storage facilities in its oil sands operations. The substance of the arrangement has been determined to be a lease and has been classified as a finance lease. The assets are to be used for a minimum period of 20 years with options to renew.

The future minimum lease payments under existing finance leases are payable as follows:

	Within 1 year				After 1 year but no more than 5 years				More than 5 years				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015
Future minimum lease payments		35		35		140		139		764		800		939		974
Interest		30		30		112		115		505		532		647		677
Present value of minimum lease payments		33		31		102		104		153		162		288		297

Deferred revenue

The deferred revenue relates to the take or pay commitment with respect to natural gas production volumes from the Liwan 3-1 field in the Asia Pacific Region not taken by the purchaser, as per the terms of the agreement. The purchaser has until the end of the agreement to take these volumes.

Consolidated Financial Statements  36

Note 18 Income Taxes

The major components of income tax expense for the years ended December 31, 2016 and 2015 were as follows:

Income Tax Expense (Recovery)

($ millions)	2016			2015
Current income tax
Current income tax charge		90			308
Adjustments to current income tax estimates		(91	)		(2	)
		(1	)		306
Deferred income tax
Relating to origination and reversal of temporary differences		(121	)		(1,760	)
Adjustments to deferred income tax estimates		150			(67	)
		29			(1,827	)

Deferred Tax Items in OCI

($ millions)	2016			2015
Deferred tax items expensed (recovered) directly in OCI
Derivatives designated as cash flow hedges		(1	)		(1	)
Remeasurement of pension plans		(6	)		(3	)
Exchange differences on translation of foreign operations		(40	)		215
Hedge of net investment		17			(92	)
		(30	)		119

The provision for income taxes in the consolidated statements of income (loss) reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31, 2016 and 2015 were accounted for as follows:

Reconciliation of Effective Tax Rate

($ millions, except tax rate)	2016			2015
Earnings (loss) before income taxes
Canada		615			(6,245	)
United States		5			241
Other foreign jurisdictions		330			633
		950			(5,371	)
Statutory Canadian income tax rate (percent)		27.2	%		27.0	%
Expected income tax		258			(1,450	)
Effect on income tax resulting from:
Capital gains and losses		—			2
Foreign jurisdictions		(3	)		23
Non-taxable items		(272	)		(31	)
Revaluation of foreign tax pools		(11	)		(14	)
Other – net		56			(51	)
Income tax expense (recovery)		28			(1,521	)

The statutory tax rate is 27.2 percent in 2016 (2015 – 27.0 percent). The 2015 to 2016 tax rates were similar due to no significant changes to applicable tax rates.

Consolidated Financial Statements  37

The following reconciles the movements in the deferred income tax liabilities and assets:

Deferred Tax Liabilities and Assets

($millions)	January 1, 2016			Recognized in Earnings			Recognized in OCI			Other		December 31, 2016
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(4,233	)		187			48			—		(3,998	)
Foreign exchange gains taxable on realization		(42	)		(166	)		(16	)		—		(224	)
Debt issue costs		(1	)		(1	)		—			—		(2	)
Other temporary differences		141			(162	)		—			—		(21	)
Deferred tax assets
Pension plans		43			(17	)		6			—		32
Asset retirement obligations		892			(196	)		(3	)		—		693
Loss carry-forwards		75			319			(5	)		—		389
Financial assets at fair value		13			7			—			—		20
		(3,112	)		(29	)		30			—		(3,111	)

Deferred Tax Liabilities and Assets

($millions)	January 1, 2015			Recognized in Earnings			Recognized in OCI			Other			December 31, 2015
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(5,840	)		1,853			(240	)		(6	)		(4,233	)
Foreign exchange gains taxable on realization		(35	)		(100	)		93			—			(42	)
Debt issue costs		(1	)		—			—			—			(1	)
Deferred tax assets
Pension plans		39			1			3			—			43
Asset retirement obligations		870			6			16			—			892
Loss carry-forwards		87			(21	)		9			—			75
Financial assets at fair value		12			1			—			—			13
Other temporary differences		54			87			—			—			141
		(4,814	)		1,827			(119	)		(6	)		(3,112	)

The Company has temporary differences associated with its investments in its foreign subsidiaries, branches, and interests in joint ventures. At December 31, 2016, the Company has no deferred tax liabilities in respect to these investments (December 31, 2015 -nil).

At December 31, 2016, the Company had $1,257 million (December 31, 2015 – $174 million) of U.S. tax losses that will expire between 2030 and 2036. The Company has recorded deferred tax assets in respect of these losses, as there are sufficient taxable temporary differences in the U.S. jurisdiction to utilize these losses.

Consolidated Financial Statements  38

Note 19 Share Capital

Common Shares

The Company is authorized to issue an unlimited number of no par value common shares.

Common Shares	Number of Shares		Amount ($ millions)
December 31, 2014		983,738,062		6,986
Stock dividends		590,853		14
December 31, 2015		984,328,915		7,000
Stock dividends		21,122,939		296
December 31, 2016		1,005,451,854		7,296

Quarterly dividends may be declared in an amount expressed in dollars per common share or could be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume-weighted average trading price of the common shares on the principal stock exchange on which the common shares are traded. The volume-weighted average trading price of the common shares is calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares.

The Company issued stock dividends of $296 million on January 11, 2016, on account of common share dividends declared for the third quarter of 2015 (2015 – $1,167 million in cash and $14 million in common shares). The common share and cash dividend was suspended by the Board of Directors in the fourth quarter of 2015 (2015 – declared $1.20 per common share). At December 31, 2016, the Company had no common share dividends payable (December 31, 2015 – $296 million in common shares).

Preferred Shares

The Company is authorized to issue an unlimited number of no par value preferred shares.

Cumulative Redeemable Preferred Shares	Number of Shares			Amount ($ millions)
December 31, 2014		22,000,000			534
Series 5 issued, net of share issue costs		8,000,000			195
Series 7 issued, net of share issue costs		6,000,000			145
December 31, 2015		36,000,000			874
Series 1 shares converted to Series 2 shares		(1,564,068	)		(38	)
Series 2 shares converted from Series 1 shares		1,564,068			38
December 31, 2016		36,000,000			874

On February 16, 2016, Husky announced that it did not intend to exercise its right to redeem its Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) on March 31, 2016. As a result, subject to certain conditions, the holders of Series 1 Preferred Shares were notified of their right to choose one of the following options with regard to their shares: retain any or all of their Series 1 Preferred Shares and continue to receive an annual fixed rate dividend paid quarterly; or convert, on a one-for-one basis, any or all of their Series 1 Preferred Shares into Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”) of Husky Energy and receive a floating rate quarterly dividend. On March 31, 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.

Consolidated Financial Statements  39

Cumulative Redeemable Preferred Shares Dividends	2016				2015
($ millions)	Declared		Paid		Declared		Paid
Series 1 Preferred Shares		9		7		13		13
Series 2 Preferred Shares(1)		—		—		—		—
Series 3 Preferred Shares		11		8		12		12
Series 5 Preferred Shares		9		7		7		7
Series 7 Preferred Shares		7		5		4		4
		36		27		36		36

⁽¹⁾ Series 2 Preferred shares dividends declared and paid were less than $1 million.

At December 31, 2016 there were $9 million of Preferred Share dividends payable (2015 - $nil).

Holders of the Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) are entitled to receive a cumulative quarterly fixed dividend yielding 2.40 percent annually for a five year period ending March 31, 2021, as and when declared by the Company’s Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the 5-year Government of Canada bond yield plus 1.73 percent. Holders of Series 1 Preferred Shares have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”), subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter.

Holders of the Series 2 Preferred Shares are entitled to receive a cumulative quarterly floating rate dividend that is reset every quarter for a five year period ending March 31, 2021, as and when declared by the Company’s Board of Directors. The dividend rate applicable to the Series 2 Preferred Shares, for the three month period commencing September 30, 2016 but excluding December 31, 2016, was 2.242 percent based on the sum of the Government of Canada 90 day Treasury bill rate on August 31, 2016 plus 1.73 percent. Holders of Series 2 Preferred Shares have the right, at their option, to convert their shares into Series 1 Preferred Shares, subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter.

Holders of the Cumulative Redeemable Preferred Shares, Series 3 (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 and when declared by the Company’s Board of Directors. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.13 percent. Holders of Series 3 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 4 (the “Series 4 Preferred Shares”), subject to certain conditions, on December 31, 2019 and on December 31 every five years thereafter. Holders of the Series 4 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.13 percent.

On March 12, 2015, the Company issued eight million Cumulative Redeemable Preferred Shares, Series 5 (the “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. Net proceeds after share issue costs were $195 million. 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. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.57 percent. Holders of Series 5 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 6 (the “Series 6 Preferred Shares”), subject to certain conditions, on March 31, 2020 and on March 31 every five years thereafter. Holders of the Series 6 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.57 percent.

On June 17, 2015, the Company issued six million Cumulative Redeemable Preferred Shares, Series 7 (the “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. Net proceeds after share issue costs were $145 million. 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. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.52 percent. Holders of the Series 7 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 8 (the “Series 8 Preferred Shares”), subject to certain conditions, on June 30, 2020 and on June 30 every five years thereafter. Holders of the Series 8 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.52 percent.

Consolidated Financial Statements  40

Stock Option Plan

Pursuant to the Incentive Stock Option Plan (the “Option Plan”), the Company may grant from time to time to officers and employees of the Company options to purchase common shares of the Company. The term of each option is five years, and vests one-third on each of the first three anniversary dates from the grant date. The Option Plan provides the option holder with the right to exercise the option to acquire one common share at the exercise price or surrender the option for a cash payment. The exercise price of the option is equal to the weighted average trading price of the Company’s common shares during the five trading days prior to the grant date. When the stock option is surrendered to the Company, the cash payment is equal to the excess of the aggregate fair market value of the common shares able to be purchased pursuant to the vested and exercisable portion of such stock options on the date of surrender over the aggregate exercise price for those common shares pursuant to those stock options. The fair market value of common shares is calculated as the closing price of the common shares on the date on which board lots of common shares have traded immediately preceding the date a holder of the stock options provides notice to the Company that he or she wishes to surrender his or her stock options to the Company in lieu of exercise.

Included in accounts payable and accrued liabilities and other long-term liabilities in the consolidated balance sheets at December 31, 2016 was $8 million (December 31, 2015 – $1 million) representing the estimated fair value of options outstanding. The total expense recognized in selling, general and administrative expenses in the consolidated statements of income (loss) for the Option Plan for the year ended December 31, 2016 was $7 million (2015 – $39 million recovery). At December 31, 2016, stock options exercisable for cash had an intrinsic value of $1 million (December 31, 2015 – nil).

The following options to purchase common shares have been awarded to officers and certain other employees:

Outstanding and Exercisable Options	2016					2015
	Number of Options (thousands)			Weighted Average Exercise Prices ($)		Number of Options (thousands)			Weighted Average Exercise Prices ($)
Outstanding, beginning of year		27,621			28.79		26,742			29.47
Granted(1)		5,381			15.67		5,681			25.35
Surrendered for cash		—			—		(632	)		26.65
Expired or forfeited		(7,543	)		27.94		(4,170	)		28.76
Outstanding, end of year		25,459			26.26		27,621			28.79
Exercisable, end of year		15,662			29.03		16,635			28.59

⁽¹⁾ Options granted during the year ended December 31, 2016 were attributed a fair value of $2.26 per option (2015 – $2.56) at grant date.

Outstanding and Exercisable Options	Outstanding Options						Exercisable Options
Range of Exercise Price	Number of Options (thousands)		Weighted Average Exercise Prices ($)		Weighted Average Contractual Life (years)		Number of Options (thousands)		Weighted Average Exercise Prices ($)
$14.20 – $29.99		15,889		22.44		2.46		7,752		25.60
$30.00 – $36.20		9,570		32.59		1.71		7,910		32.39
December 31, 2016		25,459		26.26		2.18		15,662		29.03

Consolidated Financial Statements  41

The fair value of the share options is estimated at each reporting date using the Black-Scholes option pricing model, taking into account the terms and conditions upon which the share options are granted and for the performance options, the current likelihood of achieving the specified target. The following table lists the assumptions used in the Black-Scholes option pricing model for the share options and performance options:

Black-Scholes Assumptions	December 31, 2016		December 31, 2015
	Tandem Options		Tandem Options
Dividend per option		0.96		1.20
Range of expected volatilities used (percent)		24.9 - 39.6		24.6 - 54.8
Range of risk-free interest rates used (percent)		0.4 - 1.1		0.4 - 0.7
Expected life of share options from vesting date (years)		1.91		1.86
Expected forfeiture rate (percent)		9.3		9.4
Weighted average exercise price		27.72		29.03
Weighted average fair value		0.37		0.03

The expected life of the share options is based on historical data and current expectations and is not necessarily indicative of exercise patterns that may occur. The expected volatility reflects the assumption that the historical volatility over a period similar to the expected life of the options is indicative of future trends, which may also not necessarily be the actual outcome.

Performance Share Units

In February 2010, the Compensation Committee of the Board of Directors of the Company established the Performance Share Unit Plan for executive officers and certain employees of the Company. The term of each PSU is three years, and the PSU vests on the second and third anniversary dates of the grant date in percentages determined by the Compensation Committee based on the Company’s total shareholder return relative to a peer group of companies and achieving a ROCIU target set by the Company. ROCIU equals net earnings plus after tax interest expense divided by the two-year average capital employed, less any capital invested in assets that are not in use. Net earnings is adjusted for the difference between actual realized and budgeted commodity prices and foreign exchange rates and other actual and budgeted exceptional items. Upon vesting, PSU holders receive a cash payment equal to the number of vested PSUs multiplied by the weighted average trading price of the Company’s common shares for the five preceding trading days. As at December 31, 2016, the carrying amount of the liability relating to PSUs was $24 million (December 31, 2015 – $17 million). The total expense recognized in selling, general and administrative expenses in the consolidated statements of income (loss) for the PSUs for the year ended December 31, 2016 was $26 million (2015 – nil). The Company paid out $18 million (2015 – $21 million paid) for performance share units which vested in the year. The weighted average contractual life of the PSUs at December 31, 2016 was one and a half years (December 31, 2015 – one and a half years).

The number of PSUs outstanding was as follows:

Performance Share Units	2016			2015
Beginning of year		5,122,626			4,159,228
Granted		2,250,110			2,374,330
Exercised		(1,167,256	)		(775,313	)
Forfeited		(1,341,790	)		(635,619	)
Outstanding, end of year		4,863,690			5,122,626
Vested, end of year		1,490,243			1,176,980

Consolidated Financial Statements  42

Earnings per Share

Earnings per Share

($ millions)	2016			2015
Net earnings (loss)		922			(3,850	)
Effect of dividends declared on preferred shares in the year		(36	)		(36	)
Net earnings (loss) – basic		886			(3,886	)
Dilutive effect of accounting for share options as equity-settled(1)		(3	)		(57	)
Net earnings (loss) – diluted		883			(3,943	)
(millions)
Weighted average common shares outstanding – basic and diluted		1,004.9			984.1
Earnings (loss) per share – basic ($/share)		0.88			(3.95	)
Earnings (loss) per share – diluted ($/share)		0.88			(4.01	)

⁽¹⁾ Stock-based compensation expense was $7 million based on cash-settlement for the year ended December 31, 2016 (2015 – $39 million recovery). Stock-based compensation expense was $10 million based on equity-settlement for the year ended December 31, 2016 (2015 – $18 million expense). For the year ended December 31, 2016, equity-settlement of share options was considered more dilutive than the cash-settlement of share options and as such, was used to calculate earnings per share - diluted.

For the year ended December 31, 2016, all 25 million tandem options (2015 – 28 million) were excluded from the calculation of diluted earnings per share as these options were anti-dilutive.

Note 20 Production, Operating and Transportation and Selling, General and Administrative Expenses

The following tables summarizes production, operating and transportation expenses in the consolidated statements of income (loss) for the years ended December 31, 2016 and 2015:

($ millions)	2016		2015
Services and support costs		983		1,144
Salaries and benefits		631		626
Materials, equipment rentals and leases		259		298
Energy and utility		413		450
Licensing fees		246		251
Transportation		30		62
Other		162		163
Total production, operating and transportation expenses		2,724		2,994

Consolidated Financial Statements  43

The following table summarizes selling, general and administrative expenses in the consolidated statements of income (loss) for the years ended December 31, 2016 and 2015:

($ millions)	2016		2015
Employee costs(1)		319		251
Stock based compensation(2)		33		(39	)
Contract services		85		77
Equipment rentals and leases		36		31
Maintenance and other		71		22
Total selling, general and administrative expenses		544		342

⁽¹⁾ Employee costs are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense.

⁽²⁾ Stock-based compensation expense (recovery) represents the cost to the Company for participation in share-based payment plans.

Note 21 Financial Items

Financial Items

($ millions)	2016			2015
Foreign exchange
Gains (losses) on translation of U.S. dollar denominated long-term debt		—			(34	)
Gains on non-cash working capital		4			35
Other foreign exchange gains		9			42
Net foreign exchange gains		13			43
Finance income		17			35
Finance expenses
Long-term debt		(330	)		(300	)
Contribution payable (note 11)		(6	)		(16	)
Other		(17	)		(18	)
		(353	)		(334	)
Interest capitalized(1)		78			157
		(275	)		(177	)
Accretion of asset retirement obligations (note 16)		(126	)		(121	)
Finance expenses		(401	)		(298	)
Total Financial Items		(371	)		(220	)

⁽¹⁾  Interest capitalized on project costs in 2016 is calculated using the Company’s annualized effective interest rate of 5 percent (2015 – 5 percent).

Consolidated Financial Statements  44

Note 22 Pensions and Other Post-employment Benefits

The Company currently provides defined contribution pension plans for all qualified employees and two other post-employment benefit plans to its retirees. The other post-employment benefit plan provides certain retired employees with health care and dental benefits. The Company also maintains a defined benefit pension plan, which is closed to new entrants. The defined benefit pension plan provides pension benefits to certain employees based on years of service and final average earnings. The amount and timing of funding of these plans is subject to the funding policy as approved by the Board of Directors.

The measurement date of all plan assets and the accrued benefit obligations was December 31, 2016. The Company is required to file an actuarial valuation of its defined benefit pension with the provincial or state regulator at least every three years. The most recent actuarial valuation was December 31, 2015 for the Canadian defined benefit plan. The most recent actuarial valuation was December 31, 2014 for the Canadian Other Post-employment benefit plan. The most recent actuarial valuation of the U.S. Other Post-employment benefit plan was December 31, 2015.

Defined Contribution Pension Plan

During the year ended December 31, 2016, the Company recognized a $46 million expense (2015 – $44 million) for the defined contribution plan and the two U.S. 401(k) plans in net earnings.

Defined Benefit Pension Plan (“DB Pension Plan”) and Other Post-employment Benefit Plans (“OPEB Plans”)

Defined Benefit Obligation	DB Pension Plan						OPEB Plans
($ millions)	2016			2015			2016			2015
Beginning of year		177			179			180			143
Current service cost		1			4			13			10
Interest cost		6			7			7			6
Benefits paid		(11	)		(11	)		(3	)		(3	)
Remeasurements
Actuarial (gain) loss – experience		(1	)		—			(1	)		17
Actuarial (gain) loss – financial assumptions		6			(2	)		17			7
End of year		178			177			213			180

Fair Value of Plan Assets	DB Pension Plan						OPEB Plans
($ millions)	2016			2015			2016			2015
Beginning of year		181			180			—			—
Contributions by employer		2			2			—			—
Benefits paid		(11	)		(11	)		—			—
Interest income		6			7			—			—
Return on plan assets greater (less) than discount rate		5			3			—			—
Settlements		—			—			—			—
End of year		183			181			—			—
Funded status	DB Pension Plan						OPEB Plans
($ millions)	2016			2015			2016			2015
Net asset (liability)		5			4			(213	)		(180	)

The Company has accrued the total net liability for the DB Pension Plan and the OPEB Plans in the consolidated balance sheets in other long-term liabilities.

Consolidated Financial Statements  45

The composition of the DB Pension Plan assets at December 31, 2016 and 2015 was as follows:

DB Pension Plan Assets

(percent)	Target allocation range		2016		2015
Money market type funds		0 - 5		0.6		0.5
Equity securities		30 - 50		43.8		41.5
Debt securities		50 - 65		55.6		58.0

The following tables summarize amounts recognized in net earnings and OCI for the DB Pension Plan and the OPEB Plans for the years ended December 31, 2016 and 2015:

	DB Pension Plan						OPEB Plans
($ millions)	2016			2015			2016			2015
Amounts recognized in net earnings
Current service cost		1			4			13			10
Net Interest cost		—			—			7			6
Gain on settlement		—			—			—			—
Benefit cost (gain)		1			4			20			16
Remeasurements
Actuarial (gain) loss due to liability experience		(1	)		—			(1	)		17
Actuarial (gain) loss due to liability assumption changes		6			(2	)		17			7
Loss (gain) on plan assets		(5	)		(3	)		—			—
Remeasurement effects recognized in OCI		—			(5	)		16			24

The following long-term assumptions were used to estimate the value of the defined benefit obligations, the plan assets and the OPEB Plans:

Assumptions	DB Pension Plan				OPEB Plans
(percent)	2016		2015		2016		2015
Discount rate for benefit expense and obligation		3.5 - 3.8		3.7 - 3.8		3.7 - 4.1		3.7 - 4.1
Rate of compensation expense		3.5		3.5		N/A		N/A

The average health care cost trend rate used for the benefit expense for the Canadian OPEB Plan was 7.0 percent for 2016, grading

0.4 percent per year for 5 years to 5.0 percent in 2021 and thereafter. The average health care cost trend rate used for the obligation related to the Canadian OPEB Plan was 7.0 percent for 2016, grading 0.4 percent per year for 5 years to 5.0 percent in 2021 and thereafter.

The average health care cost trend rate used for the benefit expense for the U.S. OPEB Plan was 6.5 percent for 2016, grading 0.25 percent per year for 6 years to 5.0 percent per year in 2022 and thereafter. The average health care cost trend rate used for the obligation related to the U.S. OPEB Plan was 6.3 percent for 2016, grading 0.21 percent per year for 6 years to 5.0 percent in 2022 and thereafter.

The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumption is shown below:

Sensitivity Analysis	DB Pension Plan					OPEB Plans
($ millions)	1% increase			1% decrease		1% increase			1% decrease
Discount rate		(18	)		20		(36	)		41
Health Care Cost Trend Rate		N/A			N/A		40			(32	)

Consolidated Financial Statements  46

Note 23 Cash Flows – Change in Non-cash Working Capital

Non-cash Working Capital

($ millions)	2016			2015
Decrease (increase) in non-cash working capital
Accounts receivable		(340	)		844
Inventories		(334	)		570
Prepaid expenses		131			10
Accounts payable and accrued liabilities		316			(926	)
Change in non-cash working capital		(227	)		498
Relating to:
Operating activities		(235	)		651
Financing activities		281			179
Investing activities		(273	)		(332	)

Note 24 Financial Instruments and Risk Management

Financial Instruments

The Company’s financial instruments include cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, short-term debt, long-term debt, contribution payable, derivatives, portions of other assets and other long-term liabilities.

The following table summarizes the Company’s financial instruments that are carried at fair value in the Consolidated Balance Sheets:

Financial Instruments at Fair Value

($ millions)	December 31, 2016			December 31, 2015
Commodity contracts - fair value through profit or loss (“FVTPL”)
Natural gas(1)		5			6
Crude oil(2)		(30	)		8
Other assets - FVTPL		1			2
Hedge of net investment(3)(4)		(827	)		(940	)
End of year		(851	)		(924	)

⁽¹⁾ Natural gas contracts includes an $11 million increase at December 31, 2016 (December 31, 2015 – $14 million decrease ) to the fair value of held-for-trading inventory, recognized in the Consolidated Balance Sheets, related to third party physical purchase and sale contracts for natural gas held in storage. Total fair value of the related natural gas storage inventory was $45 million at December 31, 2016 (December 31, 2015 – $67 million).

⁽²⁾ Crude oil contracts includes an $17 million increase at December 31, 2016 (December 31, 2015 – $6 million decrease) to the fair value of held-for-trading inventory, recognized in the Consolidated Balance Sheets, related to third party crude oil physical purchase and sale contracts. Total fair value of the related crude oil inventory was $354 million at December 31, 2016 (December 31, 2015 – $190 million).

⁽³⁾ Hedging instruments are presented net of tax.

⁽⁴⁾ Represents the translation of the Company’s U. S. denominated long-term debt designated as a hedge of the Company’s net investment in its U.S. refining operations.

The Company’s other financial instruments that are not related to derivatives, contingent consideration or hedging activities are included in cash and cash equivalents, accounts receivable, restricted cash, income tax receivable, accounts payable and accrued liabilities, short-term debt, long-term debt, contribution payable, and portions of other assets and other long-term liabilities. These financial instruments are classified as loans and receivables or other financial liabilities and are carried at amortized cost. Excluding long-term debt, the carrying values of these financial instruments and cash and cash equivalents approximate their fair values.

The fair value of long-term debt represents the present value of future cash flows associated with the debt. Market information, such as treasury rates and credit spreads, are used to determine the appropriate discount rates. These fair value determinations are compared to quotes received from financial institutions to ensure reasonability. The estimated fair value of long-term debt at December 31, 2016 was $5.5 billion (December 31, 2015 – $5.6 billion).

Consolidated Financial Statements  47

The estimation of the fair value of commodity derivatives and held-for-trading inventories incorporates exit prices and adjustments for quality and location. The estimation of the fair value of interest rate and foreign currency derivatives incorporates forward market prices, which are compared to quotes received from financial institutions to ensure reasonability. The estimation of the fair value of the net investment hedge incorporates foreign exchange rates and market interest rates from financial institutions. All financial assets and liabilities are classified as Level 2 measurements.

Risk Management Overview

The Company is exposed to risks related to the volatility of commodity prices, foreign exchange rates and interest rates. It is also exposed to financial risks related to liquidity and credit and contract risks. In certain instances, the Company uses derivative instruments to manage the Company’s exposure to these risks. Derivative instruments are recorded at fair value in accounts receivable, inventory, other assets and accounts payable and accrued liabilities in the Consolidated Balance Sheets. The Company has crude oil and natural gas inventory held in storage related to commodity price risk management contracts that is recognized at fair value. The Company employs risk management strategies and policies to ensure that any exposures to risk are in compliance with the Company’s business objectives and risk tolerance levels.

Responsibility for risk management is held by the Company’s Board of Directors and is implemented and monitored by senior management within the Company.

a) Market Risk

i) Commodity Price Risk Management

All derivative instruments, other than those designated as effective hedging instruments or certain non-financial derivative contracts that meet the Company’s own use requirements, are classified as held for trading and are recorded at fair value. Gains and losses on these instruments are recorded in the consolidated statements of income in the period they occur.

In certain instances, the Company uses derivative commodity instruments and futures contracts on commodity exchanges, including commodity put and call options under a short-term hedging program, to manage exposure to price volatility on a portion of its refined product, oil and gas production, and inventory or volumes in long distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and natural gas. For the year ended December 31, 2016, the Company incurred a realized loss of $121 million on a short-term corporate hedging program, which is recorded in other-net in the Consolidated Statements of Income (Loss). The hedging program concluded in June 2016.

The Company’s results will be impacted by a decrease in the price of crude oil and natural gas inventory. The Company has crude oil inventories that are feedstock, held at terminals or part of the in-process inventories at its refineries and at offshore sites. The Company also has natural gas inventory that could have an impact on earnings based on changes in natural gas prices. All these inventories are subject to a lower of cost or net realizable value test on a monthly basis.

Foreign Exchange Risk Management

The Company’s results are affected by the exchange rates between various currencies, including the Canadian and U.S. dollar. The majority of the Company’s revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. The majority of the Company’s expenditures are in Canadian dollars. The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. revenue dollars to hedge against these fluctuations and to mitigate its exposure to foreign exchange risk.

A change in the value of the Canadian dollar against the U.S. dollar will also result in an increase or decrease in the Company’s U.S. dollar denominated debt, as expressed in Canadian dollars, as well as the related finance expense. In order to mitigate the Company’s exposure to long-term debt affected by the U.S./Canadian dollar exchange rate, the Company may enter into cash flow hedges using cross currency debt swap arrangements. In addition, the Company’s U.S. dollar denominated debt has been designated as a hedge of a net investment in a foreign operation that has a U.S. dollar functional currency. The unrealized foreign exchange gain or loss related to this hedge is recorded in OCI.

At December 31, 2016, the Company had designated U.S. $3.0 billion denominated debt as a hedge of the Company’s selected net investments in its foreign operations with a U.S. dollar functional currency (December 31, 2015 – U.S. $3.2 billion). For the year ended December 31, 2016, the unrealized gain arising from the translation of the debt was $113 million (December 31, 2015 – unrealized loss of $587 million), net of tax loss of $17 million (December 31, 2015 – recovery of $92 million), which was recorded in hedge of net investment within OCI.

Consolidated Financial Statements  48

Interest Rate Risk Management

Interest rate risk is the impact of fluctuating interest rates on earnings, cash flows and valuations. To mitigate risk related to interest rates, the Company may enter into fair value or cash flow hedges using interest rate swaps.

At December 31, 2016, the balance in long-term debt related to deferred gains resulting from unwound interest rate swaps that had previously been designated as a fair value hedge was $2 million (December 31, 2015 – $4 million). The amortization of the accrued gain upon terminating the interest rate swaps resulted in an offset to finance expenses of $2 million for the year ended December 31, 2016 (December 31, 2015 – $22 million).

At December 31, 2016, the balance in other reserves related to the accrued gain from unwound forward starting interest rate swaps designated as a cash flow hedge was $18 million (December 31, 2015 – $20 million), net of tax of $6 million (December 31, 2015 –net of tax of $7 million). The amortization of the accrued gain upon settling the interest rate swaps resulted in an offset to finance expense of $2 million for the year ended December 31, 2016 (December 31, 2015 – $3 million).

ii) Earnings Impact of Market Risk Management Contracts

The gains (losses) recognized on other risk management positions for the years ended December 31, 2016 and 2015 are set out below:

	2016
Earnings Impact ($ millions)	Marketing and Other			Other – Net			Net Foreign Exchange
Commodity Price
Natural gas		(1	)		—			—
Crude oil		(38	)		—			—
Crude oil call options		—			(67	)		—
Crude oil put options		—			(54	)		—
		(39	)		(121	)		—
Foreign Currency
Foreign currency forwards(1)		—			—			10
		(39	)		(121	)		10

⁽¹⁾ Unrealized gains or losses from short-dated foreign currency forwards are included in other – net, while realized gains or losses are included in net foreign exchange gains in the consolidated statements of income (loss).

	2015
Earnings Impact ($ millions)	Marketing and Other		Other – Net		Net Foreign Exchange
Commodity Price
Natural gas		11		—		—
Crude oil		4		—		—
		15		—		—
Foreign Currency
Foreign currency forwards(1)		—		1		(28	)
		15		1		(28	)

⁽¹⁾ Unrealized gains or losses from short-dated foreign currency forwards are included in other – net, while realized gains or losses are included in net foreign exchange gains in the consolidated statements of income (loss).

Consolidated Financial Statements  49

Offsetting Financial Assets and Liabilities

The tables below outline the financial assets and financial liabilities that are subject to set-off rights and related arrangements, and the effect of those rights and arrangements on the consolidated balance sheets:

	As at December 31, 2016
Offsetting Financial Assets and Liabilities ($ millions)	Gross Amount			Amount Offset			Net Amount
Financial Assets
Financial derivatives		57			(38	)		19
Normal purchase and sale agreements		529			(199	)		330
End of year		586			(237	)		349
Financial Liabilities
Financial derivatives		(161	)		70			(91	)
Normal purchase and sale agreements		(644	)		234			(410	)
End of year		(805	)		304			(501	)

	As at December 31, 2015
Offsetting Financial Assets and Liabilities ($ millions)	Gross Amount			Amount Offset			Net Amount
Financial Assets
Financial derivatives		87			(37	)		50
Normal purchase and sale agreements		353			(122	)		231
End of year		440			(159	)		281
Financial Liabilities
Financial derivatives		(108	)		48			(60	)
Normal purchase and sale agreements		(368	)		68			(300	)
End of year		(476	)		116			(360	)

Market Risk Sensitivity Analysis

A sensitivity analysis for commodities, foreign currency exchange and interest rate risks has been calculated by increasing or decreasing commodity prices, foreign currency exchange rates or interest rates, as appropriate. These sensitivities represent the increase or decrease in earnings before income taxes resulting from changing the relevant rates, with all other variables held constant. These sensitivities have only been applied to financial instruments held at fair value. The Company’s process for determining these sensitivities has not changed during the year.

Commodity Price Risk⁽¹⁾

($millions)	10% price increase			10% price decrease
Crude oil price		(6	)		6
Natural gas price		(7	)		7

Foreign Exchange Rate⁽²⁾

($millions)	Canadian dollar $0.01 increase		Canadian dollar $0.01 decrease
U.S. dollar per Canadian dollar(3)		—		—

⁽¹⁾  Based on average crude oil and natural gas market prices as at December 31, 2016.

⁽²⁾  Based on the U.S./Canadian dollar exchange rate as at December 31, 2016.

⁽³⁾  Foreign Exchange sensitivity on U.S. dollar per Canadian dollar is less than $1 million.

Consolidated Financial Statements  50

b) Financial Risk

i) Liquidity Risk Management

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. The Company’s processes for managing liquidity risk include ensuring, to the extent possible, that it has access to multiple sources of capital including cash and cash equivalents, cash from operating activities, undrawn credit facilities and capability to raise capital from various debt and equity capital markets under its shelf prospectuses. The Company prepares annual capital expenditure budgets, which are monitored and updated as required. In addition, the Company requires authorizations for expenditures on projects, which assists with the management of capital.

Since the Company operates in the Upstream oil and gas industry, it requires significant cash to fund capital programs necessary to maintain or increase production, develop reserves, acquire strategic oil and gas assets and repay maturing debt. The Company’s upstream capital programs are funded principally by cash provided from operating activities and issuances of debt and equity. During times of low oil and gas prices, a portion of capital programs can generally be deferred. However, due to the long cycle times and the importance to future cash flow of maintaining the Company’s production, it may be necessary to utilize alternative sources of capital to continue the Company’s strategic investment plan during periods of low commodity prices. As a result, the Company frequently evaluates the options available with respect to sources of short and long-term capital resources. Occasionally, the Company will economically hedge a portion of its production to protect cash flow in the event of commodity price declines.

The Company had the following available credit facilities as at December 31, 2016:

Credit Facilities

($ millions)	Available		Unused
Operating facilities(1)(note 13)		670		292
Syndicated bank facilities(2)(note 15)		4,000		3,800
End of year		4,670		4,092

⁽¹⁾  Consists of demand credit facilities and letter of credit.

⁽²⁾  Commercial paper outstanding is supported by the Company’s Syndicated credit facilities.

In addition to the credit facilities listed above, the Company had unused capacity under the Canadian Shelf Prospectus of $1.9 billion and unused capacity under the U.S Shelf Prospectus and related U.S registration statement of U.S. $3.0 billion. The ability of the Company to raise additional capital utilizing these Shelf Prospectuses is dependent on market conditions.

The Company believes it has sufficient funding through the use of these facilities and access to the capital markets to meet its future capital requirements.

ii) Credit and Contract Risk Management

Credit and contract risk represent the financial loss that the Company would suffer if a counterparty in a transaction fails to meet its obligations in accordance with the agreed terms. The Company actively manages its exposure to credit and contract execution risk from both a customer and a supplier perspective. The Company’s accounts receivables are broad based with customers in the energy industry and midstream and end user segments and are subject to normal industry risks. The Company’s policy to mitigate credit risk includes granting credit limits consistent with the financial strength of the counterparties and customers, requiring financial assurances as deemed necessary, reducing the amount and duration of credit exposures and close monitoring of all accounts. The Company had one external customer that constituted more than 10 percent of gross revenues during the years ended December 31, 2016 and December 31, 2015. Sales to this customer were approximately $1,832 million for the year ended December 31, 2016 (December 31, 2015 – $2,868 million).

Cash and cash equivalents include cash bank balances and short-term deposits maturing in less than three months. The Company manages the credit exposure related to short-term investments by monitoring exposures daily on a per issuer basis relative to predefined investment limits.

The carrying amounts of cash and cash equivalents, accounts receivable and restricted cash represent the Company’s maximum credit exposure.

Consolidated Financial Statements  51

The Company’s accounts receivable was aged as follows at December 31, 2016:

Accounts Receivable Aging

($ millions)	December 31, 2016
Current		873
Past due (1 – 30 days)		148
Past due (31 – 60 days)		4
Past due (61 – 90 days)		3
Past due (more than 90 days)		40
Allowance for doubtful accounts		(32	)
		1,036

The Company recognizes a valuation allowance when collection of accounts receivable is in doubt. Accounts receivable are impaired directly when collection of accounts receivable is no longer expected. For the year ended December 31, 2016, the Company wrote off $3 million (December 31, 2015 – $7 million) of uncollectible receivables.

Note 25 Related Party Transactions

Significant subsidiaries and jointly controlled entities at December 31, 2016 and the Company’s percentage equity interest (to the nearest whole number) are set out below:

Significant Subsidiaries and Joint Operations	%		Jurisdiction
Subsidiary of Husky Energy Inc.
Husky Oil Operations Limited		100		Alberta
Subsidiaries and jointly controlled entities of Husky Oil Operations Limited
Husky Oil Limited Partnership		100		Alberta
Husky Terra Nova Partnership		100		Alberta
Husky Downstream General Partnership		100		Alberta
Husky Energy Marketing Partnership		100		Alberta
Husky Energy International Corporation		100		Alberta
Sunrise Oil Sands Partnership		50		Alberta
BP-Husky Refining LLC		50		Delaware
Lima Refining Company		100		Delaware
Husky Marketing and Supply Company		100		Delaware

Each of the related party transactions described below was made on terms equivalent to those that prevail in arm’s length transactions unless otherwise noted.

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, of which Husky owns 35 percent, PAH owns 48.75 percent and CKI owns 16.25 percent. This transaction is a related party transaction, as PAH and CKI are affiliates of one of the Company’s principal shareholders, and has been measured at fair value. 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. Subsequent to the sale of its ownership interest, the Company performs management services as the operator of the pipeline for which it earns a management fee from HMLP. The Company is also the contractor for HMLP and constructs its assets on a cost recovery basis with certain restrictions. HMLP charges an access fee to the Company for the use of its pipeline systems in performing its blending business and the Company also pays for transportation and storage services. For the year ended December 31, 2016, the Company charged HMLP $133 million related to construction and management services, and the Company had purchases from HMLP of $15 million related to the use of the pipeline for the Company’s blending activities and $64 million related to transportation and storage. As at December 31, 2016, the Company had $26 million due from HMLP and nil due to HMLP related to these transactions. All transactions with HMLP have been measured at fair value.

Consolidated Financial Statements  52

The Company sells natural gas to and purchases steam from the Meridian Limited Partnership (“Meridian”), owner of the Meridian cogeneration facility, for use at the facility, Upgrader and Lloydminster ethanol plant. In addition, the Company provides facilities services and personnel for the operations of the Meridian cogeneration facility, which are primarily measured and reimbursed at cost. These transactions are related party transactions, as Meridian is an affiliate of one of the Company’s principal shareholders, and have been measured at fair value. For the year ended December 31, 2016, the amount of natural gas sales to Meridian totalled $41 million (December 31, 2015 – $50 million). For the year ended December 31, 2016, the amount of steam purchased by the Company from Meridian totalled $13 million (December 31, 2015 – $16 million). For the year ended December 31, 2016, the total cost recovery by the Company for facilities services was $12 million (December 31, 2015 – $17 million). At December 31, 2016 the Company had under $1 million due from Meridian with respect to these transactions (December 31, 2015 – $2 million).

At December 31, 2016, $34 million of the May 11, 2009 7.25 percent senior notes were held by a related party, Ace Dimension Limited, and are included in long-term debt in the Company’s consolidated balance sheet. The related party transaction was measured at fair market value at the date of the transaction and has been carried out on the same terms as applied with unrelated parties.

On June 29, 2011, the Company issued 7.4 million common shares at a price of $27.05 per share for total gross proceeds of $200 million in a private placement to its then principal shareholders, L.F. Management and Investment S.à r.l (formerly L.F. Investments (Barbados) Limited) and Hutchison Whampoa Luxembourg Holdings S.à r.l, which was completed in conjunction with a public offering by the Company of common shares.

On December 7, 2010, the Company issued 28.9 million common shares at a price of $24.50 per share for total gross proceeds of $707 million in a private placement to its principal shareholders, L.F. Management and Investment S.à r.l (formerly L.F. Investments (Barbados) Limited) and Hutchison Whampoa Luxembourg Holdings S.à r.l, which was completed in conjunction with a public offering by the Company of common shares in Canada.

The Company defines its key management as the officers and executives within the executive department of the Company. The amounts disclosed in the table below are the amounts recognized as an expense during the reporting period related to key management personnel:

Compensation of Key Management Personnel

($ millions)	2016		2015
Short-term employee benefits(1)		9		15
Stock-based compensation(2)		4		8
		13		23

⁽¹⁾ Short-term employee benefits are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense.

⁽²⁾ Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans.

Note 26 Commitments and Contingencies

At December 31, 2016, the Company had commitments that require the following minimum future payments, which are not accrued in the consolidated balance sheets:

Minimum Future Payments for Commitments

($ millions)	Within 1 year		After 1 year but not more than 5 years		More than 5 years		Total
Operating leases(1)		252		535		1,650		2,437
Firm transportation agreements(1)		458		1,851		4,822		7,131
Unconditional purchase obligations(2)		2,749		4,841		1,549		9,139
Lease rentals and exploration work agreements		49		244		850		1,143
Obligations to fund equity investee(3)		52		220		379		651
		3,560		7,691		9,250		20,501

⁽¹⁾ Included in operating leases and firm transportation agreements are blending and storage agreements and transportation commitments of $0.6 billion and $2.1 billion respectively with HMLP.

⁽²⁾ Includes purchase of refined petroleum products, processing services, distribution services, insurance premiums, drilling services and natural gas purchases.

⁽³⁾ Equity investee refers to the Company’s investment in Husky-CNOOC Madura Limited and HMLP which is accounted for using the equity method.

Consolidated Financial Statements  53

The Company has income tax and royalty filings that are subject to audit and potential reassessment. The findings may impact the liabilities of the Company. The final results are not reasonably determinable at this time, and management believes that it has adequately provided for current and deferred income taxes.

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters would have a material adverse impact on its financial position, results of operations or liquidity.

Note 27 Capital Disclosures

The Company’s objectives when managing capital are to maintain a flexible capital structure, which optimizes the cost of capital at acceptable risk, and to maintain investor, creditor and market confidence to sustain the future development of the business. The Company manages its capital structure and makes adjustments as economic conditions and the risk characteristics of its underlying assets change. The Company considers its capital structure to include shareholders’ equity and debt which was $23.0 billion as at December 31, 2016 (December 31, 2015 – $23.3 billion). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise debt and/or adjust its capital spending to manage its current and projected debt levels.

The Company monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of debt to capital employed and debt to funds from operations. Debt to capital employed is defined as long-term debt, long-term debt due within one year, and short-term debt divided by capital employed which is equal to long-term debt, long-term debt due within one year, short-term debt and shareholders’ equity. Debt to funds from operations is defined as long-term debt, long-term debt due within one year and short-term debt divided by funds from operations which is equal to cash flow - operating activities less the settlement of asset retirement obligations, deferred revenue, income taxes received (paid) and change in non-cash working capital.

The Company’s objective is to maintain a debt to capital employed target of less than 25 percent and a debt to funds from operations ratio of less than 2.0 times. At December 31, 2016, debt to capital employed was 23.2 percent (December 31, 2015 – 28.9 percent) which was within the Company’s target and debt to funds from operations was 2.6 times (December 31, 2015 – 2.0 times). The increase in the Company’s debt to funds from operations ratio as at December 31, 2016 reflects the impact of continued operations in the low commodity price environment which resulted in significantly lower funds from operations compared to 2015. The Company has taken measures to strengthen its financial position and navigate through this commodity down cycle which include, but are not limited to, a reduction of budgeted capital spending, the suspension of the quarterly common share dividend, the sale of royalty interests in Western Canada production, the sale of non-core assets in Western Canada, a strategic disposition of select midstream assets and the continued transition to lower sustaining and higher return Lloyd thermal projects. To facilitate the management of these ratios, the Company prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors.

The Company’s share capital is not subject to external restrictions; however, the syndicated credit facilities include a debt to capital covenant used to assess the Company’s financial strength. The Company’s leverage covenant under both of its revolving syndicated credit facilities was modified to a debt to capital covenant calculated as total debt (long-term debt including long-term debt due within one year and short-term debt) and certain adjusting items specified in the agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the agreement. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2016 and assesses the risk of non-compliance to be low.

There were no changes in the Company’s approach to capital management from the previous year.

Note 28 Government Grants

The Company has government assistance programs in place where it receives funding based on ethanol production and sales from the Lloydminster and Minnedosa ethanol plants from the Department of Natural Resources and the Government of Manitoba. Applications for funding are submitted quarterly. During 2015, the Company received $21 million under these programs. The programs expired in 2015.

Consolidated Financial Statements  54

Document C

Form 40-F

Management’s Discussion and Analysis

MANAGEMENT’S DISCUSSION AND ANALYSIS

1.0 Financial Summary

1.1 Financial Position

Total Assets ($ billions)	Total Equity ($ billions)	Total Long-term Debt ($ billions)	Debt to Capital Employed(1) (%)	Debt to Funds from Operations(1) (times)

1.2 Financial Performance

Net Earnings ($ billions)	Cash Flow ($ billions)

⁽¹⁾ Debt to capital employed, debt to funds from operations and adjusted net earnings are non-GAAP measures. Adjusted net earnings was redefined in the second quarter of 2016 to equal net earnings before after-tax property, plant and equipment impairment (reversal), goodwill impairment charges, exploration and evaluation asset write-downs, inventory write-downs and loss (gain) on sale of assets. Prior periods have been revised to conform with the current period presentation. Refer to Section 11.3 for a reconciliation to the GAAP measures.

Management’s Discussion and Analysis 2016

1

1.3 Total Shareholder Returns

The following graph shows the total shareholder returns compared with the Standard and Poor’s (“S&P”) and the Toronto Stock Exchange (“TSX”) energy and composite indices.

Total Shareholder Returns

^(%)

1.4 Selected Annual Information

($ millions, except where indicated)	2016			2015			2014
Gross revenues and Marketing and other		13,224			16,801			25,122
Net earnings (loss) by business segment
Upstream		1,091			(4,254	)		1,106
Downstream		342			660			363
Corporate		(511	)		(256	)		(211	)
Net earnings (loss)		922			(3,850	)		1,258
Net earnings (loss) per share – basic		0.88			(3.95	)		1.26
Net earnings (loss) per share – diluted		0.88			(4.01	)		1.20
Adjusted net earnings (loss)(1)		(655	)		149			1,992
Funds from operations(1)		2,076			3,329			5,535
Ordinary dividends per common share(2)		—			0.90			1.20
Dividends per cumulative redeemable preferred share, series 1		0.73			1.11			1.11
Dividends per cumulative redeemable preferred share, series 2		0.42			—			—
Dividends per cumulative redeemable preferred share, series 3		1.13			1.19			—
Dividends per cumulative redeemable preferred share, series 5		1.25			0.90			—
Dividends per cumulative redeemable preferred share, series 7		1.15			0.62			—
Total assets		32,260			33,056			38,848
Net debt(3)		4,020			6,686			4,025

⁽¹⁾ Adjusted net earnings and funds from operations are non-GAAP measures. Adjusted net earnings was redefined in the second quarter of 2016 to equal net earnings before after-tax property, plant and equipment impairment (reversal), goodwill impairment charges, exploration and evaluation asset write-downs, inventory write-downs and loss (gain) on sale of assets. Prior periods have been revised to conform with the current period presentation. Refer to Section 11.3 for a reconciliation to the GAAP measures.

⁽²⁾ Dividends declared for the third quarter of 2015 were issued in the form of common shares. The quarterly common share dividend was suspended in the fourth quarter of 2015.

⁽³⁾ Net debt is a non-GAAP measure. Refer to Section 11.3 for a reconciliation to the GAAP measure.

Management’s Discussion and Analysis 2016

2

2.0 Husky Business Overview

Husky Energy Inc. (“Husky” or the “Company”) is one of Canada’s largest integrated energy companies and is based in Calgary, Alberta. The Company’s common shares are listed on the Toronto Stock Exchange (“TSX”) under the symbol “HSE” and the Cumulative Redeemable Preferred Shares Series 1, Series 2, Series 3, Series 5 and Series 7 are listed under the symbols, “HSE.PR.A”, “HSE.PR.B”, “HSE.PR.C”, “HSE.PR.E” and “HSE.PR.G”, respectively. The Company operates in Canada, the United States and the Asia Pacific Region with Upstream and Downstream business segments. The Company’s balanced growth strategy focuses on consistent execution, disciplined financial management and safe and reliable operations.

2.1 Upstream

Upstream includes exploration for, and development and production of, crude oil, bitumen, natural gas and natural gas liquids (“NGL”) (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).

Profile and highlights of the Upstream segment include:

Heavy Oil

• The heavy oil thermal portfolio, including the Tucker Thermal Project, averaged 84,600 bbls/day in 2016, compared to 59,900 bbls/ day in 2015;

• First oil was achieved at the 10,000 bbls/day Edam East heavy oil thermal development in the second quarter of 2016. Production averaged 14,900 bbls/day in December, exceeding its design capacity;

• First oil was achieved at the 10,000 bbls/day Vawn heavy oil thermal development in the second quarter of 2016. Production averaged 11,400 bbls/day in December, exceeding its design capacity;

• First oil was achieved at the 4,500 bbls/day Edam West heavy oil thermal development in the third quarter of 2016. Production averaged 4,200 bbls/day in December;

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

• Development continues at the 10,000 bbls/day Rush Lake 2 heavy oil thermal development, with first production expected in the first half of 2019; and

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

Oil Sands

• Gross production from the Sunrise Energy Project continued to ramp-up in 2016, averaging 25,600 bbls/day (12,800 bbls/day net Husky share) during 2016, 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).

Asia Pacific Region

• The Liwan Gas Project, the first deepwater development offshore China, consists of three deepwater natural gas fields: Liwan 3-1, Liuhua 34-2 and Liuhua 29-1. The Company holds a 49 percent working interest in the production sharing contract (“PSC”) at the Liwan Gas Project and operates the deepwater infrastructure;

• Combined gross production from Liwan 3-1 and Liuhua 34-2 averaged 48,800 boe/day (24,800 boe/day net Husky share) in 2016, compared to 62,300 boe/day (38,400 boe/day net Husky share) in 2015. The decrease in the overall production is due to issues within the buyer’s onshore pipeline network in the first quarter of 2016 and reduced buyer gas demand in 2016. The decrease in the Company’s net share of production was also due to the entitlement share of production volumes reverting back to 49 percent in the second quarter of 2015 following the completion of exploration cost recoveries from the Liwan 3-1 field;

• 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 to set the price at Cdn. $12.50- Cdn. $15.00 per mcf at the current exchange rates. Gross take-or-pay volumes from the fields remain unchanged in the range of 300-330 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;

• The second 22-inch subsea pipeline connecting the deepwater pipeline to the central platform has been 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;

• Negotiations for the sale of gas and liquids from Liuhua 29-1, the third deepwater field, are being pursued together with CNOOC;

Management’s Discussion and Analysis 2016

3

• The Company holds a 40 percent working interest in the Wenchang oil field, located in the Pearl River Mouth Basin approximately 400 kilometres southwest of the Hong Kong Special Administrative Region. The PSC will expire in the fourth quarter of 2017, after which the Company will not have a working interest in this field;

• In 2015, the Company signed a PSC for the 15/33 exploration block offshore China. The 15/33 block covers approximately 155 square kilometres and is located in the Pearl River Mouth Basin in the South China Sea, approximately 140 kilometres southeast of the Hong Kong Special Administrative Region, 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. The corresponding CNOOC share of exploration cost recovery from production would be allocated to the Company;

• The Company holds a 40 percent working interest in a joint venture company that holds the PSC for the Madura Strait Block covering approximately 622,000 acres, offshore Indonesia. It is focused on the development of the BD, MDA, MBH, MDK and MAC fields;

• The liquids-rich BD field, which is the first gas development the Company is advancing in Indonesia, remains on target for first production in 2017 and is scheduled to ramp up to its full gas sales rate by the second half of 2017;

• At the MDA, MBH and MDK gas fields, the Company has secured a gas sales agreement for the MDA and MBH fields, which will be developed in tandem. Production from the MDA, MBH and MDK gas fields is expected in the 2018 - 2019 timeframe;

• Combined net sales volumes from the BD, MDA, MBH and MDK fields are expected to be about 100 mmcf/day of gas and 2,400 boe/day of associated NGL once fully ramped up;

• Longer term, the MAC field is proceeding with front-end engineering and design (“FEED”) for development and the Company has three additional discoveries in the Madura Straight Block that are under evaluation for development;

• The Company has a 100 percent interest in the rights to the Anugerah exploration block covering approximately two million acres. The Anugerah exploration block is located in the East Java Basin, Indonesia approximately 150 kilometres east of the Madura Strait Block; and

• The Company and its joint venture partner 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.

Atlantic Region

• The Company is the operator of the White Rose field with a 72.5 percent working interest in the core field and a 68.875 percent working interest in satellite tiebacks, including the North Amethyst, South White Rose and West White Rose extensions. The Company has a 13 percent non-operated interest in the Terra Nova oil field;

• First production was achieved from the North Amethyst Hibernia formation well in the third quarter of 2016 and an additional well was brought into production at the South White Rose drill centre in the fourth quarter of 2016;

• Engineering design and subsurface evaluation work continues at West White Rose to increase capital efficiency and improve resource capture. The project will be considered for sanction in 2017;

• 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 Licenses (“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; and

• The Company has a 35 percent non-operated working interest in five discoveries in the Flemish Pass: Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen.

Western Canada Resource Play Development

• Expertise and experience exploring and developing the natural gas potential in the Alberta Deep Basin, Foothills and Northwest Plains of Alberta and British Columbia.

Infrastructure and Marketing

• The Infrastructure and Marketing business supports Upstream production while providing integration with the Company’s Downstream assets through optimization of market access;

• The Infrastructure and Marketing business manages the sale and transportation of the Company’s Upstream and Downstream production and third-party commodity trading volumes through access to capacity on third-party pipelines and storage facilities in both Canada and the United States; and

• Plans to expand export pipeline access and production storage opportunities to enhance market access for the Company’s heavy oil production are being evaluated.

2.2 Downstream

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.

Management’s Discussion and Analysis 2016

4

Profile and highlights of the Downstream segment include:

Upgrading

• Heavy oil upgrading facility located in Lloydminster, Saskatchewan with a throughput capacity of 82 mbbls/day.

Canadian Refined Products

• Largest marketer of paving asphalt in Western Canada with a 29 mbbls/day capacity asphalt refinery located in Lloydminster, Alberta integrated with the local heavy oil production, transportation and upgrading infrastructure;

• Largest producer of ethanol in Western Canada with a combined 260 million litres per year of capacity at plants located in Lloydminster, Saskatchewan and Minnedosa, Manitoba;

• Refinery at Prince George, British Columbia with throughput capacity of 12 mbbls/day producing low sulphur gasoline and ultra low sulphur diesel;

• Major regional motor fuel marketer with an average of 481 retail marketing locations in 2016, including bulk plants and travel centres with strategic land positions in Western Canada and Ontario. The Company also entered into a contractual agreement with Imperial Oil to create a single expanded truck transport network of approximately 160 sites. The agreement was approved by Canada’s Competition Bureau in June 2016 and contract closing conditions were met late in the fourth quarter 2016. Progress continues to be made on the implementation of the agreement, and the consolidation of the two networks is expected in the second half of 2017; and

• The Company has started the pre-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.

U.S. Refining and Marketing

• Refinery in Lima, Ohio with a gross crude oil throughput capacity of 165,000 bbls/day and operating capacity of 140,000 – 165,000 bbls/day on its current crude slate. The Company continues 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. Current heavy crude oil feedstock capability is up to 10,000 bbls/day. The full scope of the project is expected to be completed in 2018; and

• A 50 percent interest in the BP-Husky Refinery in Toledo, Ohio with a nameplate capacity of 160,000 bbls/day and operating capacity of 135,000 – 145,000 bbls/day on its current crude slate. 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 content naphthenic acids (“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.

2.3 Divestitures

• On May 25, 2016, the Company completed the sale of royalty interests representing approximately 1,700 boe/day of Western Canada production for gross proceeds of $165 million;

• 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 the Company 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; and

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

2.4 Saskatchewan Pipeline Spill Recovery Efforts

• During the third quarter of 2016, a pipeline leak occurred on the south shore of the North Saskatchewan River, spilling approximately 225 m³ (+/- 10 percent) of heavy oil and diluent. Approximately 210 m3 was recovered in cleanup operations completed in 2016; and

• As at December 31, 2016, total gross costs incurred in response to the spill were approximately $107 million, for which $88 million has been recovered through insurance proceeds. Both the spill costs and insurance recoveries have been incurred by HMLP. The Company is the operator of the assets within HMLP and holds a 35 percent interest.

Management’s Discussion and Analysis 2016

5

3.0 The 2016 Business Environment

The Company’s operations are significantly influenced by domestic and international business environment factors including, but

not limited to the following:

• The imbalance between global crude oil supply and demand, led primarily by the growth in U.S. unconventional and the Organization of the Petroleum Exporting Countries (“OPEC”) production, lower economic growth forecasts from emerging markets and corresponding growth in global crude oil inventories, resulted in the continued weakness of key crude oil benchmarks. However, in late 2016, OPEC came to an agreement to reduce production by 1.2 mmbbls/day from their daily production, which has led to crude oil benchmarks showing signs of recovery in the fourth quarter;

• North American natural gas benchmarks continued to be weak in 2016 due to an oversupply of natural gas in North America, which is largely the result of technological advances in horizontal drilling and hydraulic fracturing that have unlocked significant reserves;

• The Canadian dollar continued to be weak relative to the U.S. dollar in 2016;

• In early 2016, the Alberta government adopted the recommendation of its Royalty Review Panel. The new royalty framework preserves the existing royalty structure and rates for oil sands. It also creates a harmonized royalty formula for crude oil, natural gas and NGL that emulates a revenue minus cost system. The new rates will be calibrated to match rates of returns that could be expected under the existing system. The royalty changes will take effect in 2017 and only apply to new wells. Royalties on existing wells will remain in place for 10 years;

• Reduced production from the Western Canadian oil sands resulting from a temporary production interruption in May due to the Fort McMurray wildfire;

• Industry advancement in alternative and improved extraction methods have rapidly evolved in North American and international onshore and offshore activity;

• A continuing emphasis on environmental, health and safety, enterprise risk management, resource sustainability and corporate social responsibility;

• Transportation constraints on crude oil produced in Western Canada. The oil and gas industry continues to work with stakeholders to develop a strong network of transportation infrastructure including pipelines, rail, marine and trucks. The development of a strong infrastructure network continues to be an important challenge for the industry in order to obtain market access for the growing supply of crude oil from the Western Canadian oil sands;

• The increasing targets in the U.S. Renewable Fuel Standard (“RFS”) program have led to an increase in the price of Renewable Identification Number (“RIN”) credits for U.S. refiners;

• The convergence of North American and International crude oil prices has led to a decrease in crack spreads for North American refiners; and

• Continued global economic uncertainty has led to a tightening of investment from historical norms, creating greater competition among companies within capital markets and the postponement of various capital projects.

Major business factors are considered in the formulation of the Company’s short and longer term business strategy.

The Company is exposed to a number of risks inherent to the exploration, development, production, marketing, transportation, storage and sale of crude oil, liquids-rich natural gas and related products. For a discussion on Risk and Risk Management, see Section 7.0 and the 2016 Annual Information Form.

Commodity prices, refining crack spreads and foreign exchange rates are some of the most significant factors that affect the results of the Company’s operations. The following average benchmarks have been provided to assist in understanding the Company’s financial results.

Management’s Discussion and Analysis 2016

6

Average Benchmarks

Average Benchmarks Summary		2016		2015
West Texas Intermediate (“WTI”) crude oil(1)	(U.S. $/bbl)		43.32		48.80
Brent crude oil(2)	(U.S. $/bbl)		43.69		52.46
Light sweet at Edmonton	($/bbl)		52.99		57.21
Daqing(3)	(U.S. $/bbl)		40.86		49.26
Western Canada Select at Hardisty(4)	(U.S. $/bbl)		29.48		35.28
Lloyd heavy crude oil at Lloydminster	($/bbl)		32.61		39.15
WTI/Lloyd crude blend differential	(U.S. $/bbl)		13.70		13.43
Condensate at Edmonton	(U.S. $/bbl)		42.47		47.36
NYMEX natural gas(5)	(U.S. $/mmbtu)		2.46		2.66
Nova Inventory Transfer (“NIT”) natural gas	($/GJ)		1.98		2.62
Chicago Regular Unleaded Gasoline	(U.S. $/bbl)		56.07		67.11
Chicago Ultra-low Sulphur Diesel	(U.S. $/bbl)		56.48		68.02
Chicago 3:2:1 crack spread	(U.S. $/bbl)		12.74		18.62
U.S./Canadian dollar exchange rate	(U.S. $)		0.755		0.783
Canadian Equivalents(6)
WTI crude oil	($/bbl)		57.38		62.32
Brent crude oil	($/bbl)		57.87		67.00
Daqing	($/bbl)		54.12		62.91
Western Canada Select at Hardisty	($/bbl)		39.05		45.06
WTI/Lloyd crude blend differential	($/bbl)		18.15		17.15
NYMEX natural gas	($/mmbtu)		3.26		3.40

⁽¹⁾ Calendar Month Average of settled prices for West Texas Intermediate at Cushing, Oklahoma.

⁽²⁾ Calendar Month Average of settled prices for Dated Brent.

⁽³⁾ Calendar Month Average of settled prices for Daqing.

⁽⁴⁾ Western Canadian Select is a heavy blended crude oil, comprised of conventional and bitumen crude oils, blended with diluent, which terminals at Hardisty, Alberta. Quoted prices are indicative of the Index for Western Canadian Select at Hardisty, Alberta, set in the month prior to delivery.

⁽⁵⁾ Prices quoted are average settlement prices during the period.

⁽⁶⁾ Prices quoted are calculated using U.S. dollar benchmark commodity prices and U.S./Canadian dollar exchange rates.

As an integrated producer, the Company’s profitability is largely determined by realized prices for crude oil and natural gas, marketing margins on committed pipeline capacity and refinery margins, as well as the effect of changes in the U.S./Canadian dollar exchange rate. All of Husky’s crude oil production and the majority of its natural gas production receives the prevailing market price. The price realized for crude oil is determined by North American and global factors. The price realized for natural gas production from Western Canada is determined primarily by North American fundamentals since virtually all natural gas production in North America is consumed by North American customers, predominantly in the United States. In the Asia Pacific Region, natural gas is sold to a specific buyer with long-term contracts. For the Liwan 3-1 gas field, a price profile has been fixed for five years and then will be linked to local benchmark pricing for the years following subject to a floor and ceiling. For the Liuhua 34-2 field, the price is fixed with a single escalation step during the contract delivery period.

The Downstream segment is heavily impacted by the price of crude oil and natural gas, as the largest cost factor in the Downstream segment is crude oil feedstock, a portion of which is heavy crude oil. In the Upgrading business, heavy crude oil feedstock is processed into light synthetic crude oil. The Company’s U.S. Refining and Marketing business processes a mix of different types of crude oil from various sources, but the mix is primarily light sweet crude oil at the Lima Refinery and approximately 52 percent heavy crude oil feedstock at the BP-Husky Toledo Refinery. The Company’s Canadian Refined Products business relies primarily on purchased refined products for resale in the retail distribution network. Refined products are acquired, under supply contracts, from other Canadian refiners at rack prices or from production from the Husky Prince George Refinery.

Management’s Discussion and Analysis 2016

7

Crude Oil Benchmarks

WTI, Brent and Husky Average Crude Oil Prices	Average WTI and Brent
(U.S. $/bbl)	(U.S. $/bbl)

Global crude oil benchmarks remained weak during 2016 due to the continued market imbalance between supply and demand. While crude oil production in the U.S. has declined relative to 2015, it remained at near record levels. Towards the end of 2016, OPEC members and some key non-OPEC producers agreed to reduce production in 2017 which has improved the outlook for global crude oil benchmarks. West Texas Intermediate (“WTI”) reached a low of U.S. $26.21/bbl in the first quarter of 2016 and subsequently increased to an average of U.S. $49.29/bbl during the fourth quarter of 2016. WTI averaged U.S. $43.32/bbl in 2016, which was weaker compared to 2015 when WTI averaged U.S. $48.80/bbl. Brent averaged U.S. $43.69/bbl in 2016 compared to U.S. $52.46/bbl in 2015.

The price received by the Company for crude oil production from Western Canada is primarily driven by the price of WTI, adjusted to Western Canada. The price received by the Company for crude oil production from the Atlantic Region is primarily driven by the price of Brent and the price received by the Company for crude oil and NGL production from the Asia Pacific Region is primarily driven by the price of Daqing. A portion of the Company’s crude oil production from Western Canada is classified as either heavy crude oil or bitumen, which trades at a discount to light crude oil. In 2016, 66 percent of the Company’s crude oil and NGLs production was heavy crude oil or bitumen compared to 57 percent in 2015.

The Company’s heavy crude oil and bitumen production is blended with diluent (condensate) in order to facilitate its transportation through pipelines. Therefore, the price received for a barrel of blended heavy crude oil or bitumen is impacted by the prevailing market price for condensate. The price of condensate at Edmonton decreased in 2016 primarily due to lower expected demand growth from oil sands and declining market benchmarks for energy commodities.

Natural Gas Benchmarks

NYMEX Natural Gas, NIT Natural Gas and Husky Average Natural Gas Prices Average NYMEX (U.S. $/mmbtu)

North American natural gas benchmarks continued to be weak in 2016 due to an oversupply of natural gas in North America, which is largely the result of technological advances in horizontal drilling and hydraulic fracturing which have unlocked significant reserves that were not economical under previously applied extraction methods. The Nova Inventory Transfer (“NIT”) natural gas benchmark observed a temporary decline in the second quarter of 2016 due to reduced demand from Canadian oil sands operations, which were impacted by the Fort McMurray wildfire.

Management’s Discussion and Analysis 2016

8

The price received by the Company for natural gas production from Western Canada is primarily driven by the NIT near-month contract price of natural gas, while the price received by the Company for production from the Asia Pacific Region are covered by fixed long-term sales contracts.

North American natural gas is consumed internally by the Company’s Upstream and Downstream operations, which mitigates the impact of weak natural gas benchmark prices on the Company’s results.

Refining Benchmarks

Chicago Average Crack Spread and Husky Realized U.S. Refining Margin (U.S. $/bbl)       Average Crack Spread       (U.S. $/bbl)

The 3:2:1 crack spread is the key indicator for refining margins and reflects refinery gasoline output that is approximately twice the distillate output. This crack spread is calculated as the price of two-thirds of a barrel of gasoline plus one-third of a barrel of distillate fuel less one barrel of crude oil. Market crack spreads are based on quoted near-month contracts for WTI and spot prices for gasoline and diesel and do not reflect the actual crude purchase costs nor the product configuration of a specific refinery. The Chicago Regular Unleaded Gasoline and the Chicago Ultra-low Sulphur Diesel average benchmark prices are the standard products included in the Chicago 3:2:1 market crack spread benchmark.

The cost of the Renewable Fuels Standard legislation has become a material economic factor for refineries in the U.S. as the market value of RINs has risen. The 3:2:1 crack spread is a gross margin based on the prices of unblended fuels that will be blended with biofuel. The cost of purchasing RINs or physical biofuel blending into a final gasoline or diesel has not been deducted from the Chicago 3:2:1 gross margin. The market value of gasoline or distillate that has been blended may be lower than the value of unblended petroleum products given the value a buyer of unblended petroleum can gain by generating a RIN through blending. Husky sells both blended fuels and unblended fuels with the goal of maximizing revenue net of RINs purchases.

The Company’s realized refining margins are affected by the product configuration of its refineries, crude oil feedstock, product slates, transportation costs to benchmark hubs and the time lag between the purchase and delivery of crude oil. The product slates produced at the Lima and BP-Husky Toledo Refineries contain approximately 10 to 15 percent of other products that are sold at discounted market prices compared to gasoline and distillate. The Company’s realized refining margins are accounted for on a first in first out (“FIFO”) basis in accordance with International Financial Reporting Standards (“IFRS”).

Management’s Discussion and Analysis 2016

9

Foreign Exchange

Average U.S./Canadian Dollar Exchange Rate (U.S. $ per Cdn $) Average U.S./Canadian Dollar Exchange Rate (U.S. $ per Cdn $)

The majority of the Company’s revenues are received in U.S. dollars from the sale of oil and gas commodities and refined products whose prices are determined by reference to U.S. benchmark prices. The majority of the Company’s non-hydrocarbon related expenditures are denominated in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, changes in foreign exchange rates impact the translation of U.S. Downstream and Asia Pacific operations and U.S. dollar denominated debt. The Company’s earnings benefited from the weakening of the Canadian dollar in 2016, which averaged U.S. $0.755 compared to U.S.

$0.783 in 2015.

The Company’s fixed long-term sales contracts in the Asia Pacific Region are priced in Chinese Yuan (“RMB”) and therefore, an increase in the value of RMB relative to the Canadian dollar will increase the revenues received in Canadian dollars from the sale of natural gas commodities in the region. The Canadian dollar averaged RMB 5.01 in 2016 compared to RMB 4.92 in 2015.

Sensitivity Analysis

The following table is indicative of the impact of changes in certain key variables in 2016 on earnings before income taxes and net earnings. The table below reflects what the expected effect would have been on the financial results for 2016 had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during 2016. Each separate item in the sensitivity analysis shows the approximate effect of an increase in that variable only; all other variables are held constant. While these sensitivities are indicative for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or upon greater magnitudes of change.

Sensitivity Analysis	2016 Average		Increase	Effect on Earnings before Income  Taxes(1)						Effect on Net Earnings(1)
				($ millions)			($/share)(2)			($ millions)			($/share)(2)
WTI benchmark crude oil price(3)(4)		43.32	U.S. $1.00/bbl		101			0.10			73			0.07
NYMEX benchmark natural gas price(5)		2.46	U.S. $0.20/mmbtu		14			0.01			11			0.01
WTI/Lloyd crude blend differential(6)		13.70	U.S. $1.00/bbl		(56	)		(0.06	)		(42	)		(0.04	)
Canadian light oil margins		0.057	Cdn $0.005/litre		12			0.01			9			0.01
Asphalt margins		20.80	Cdn $1.00/bbl		10			0.01			8			0.01
Chicago 3:2:1 crack spread		12.74	U.S. $1.00/bbl		80			0.08			51			0.05
Exchange rate (U.S. $ per Cdn $)(3)(7)		0.755	U.S. $0.01		(45	)		(0.04	)		(33	)		(0.03	)

⁽¹⁾  Excludes mark to market accounting impacts.

⁽²⁾ Based on 1,005.5 million common shares outstanding as of December 31, 2016.

⁽³⁾ Does not include gains or losses on inventory.

⁽⁴⁾ Includes impacts related to Brent based production.

⁽⁵⁾ Includes impact of natural gas consumption.

⁽⁶⁾  Excludes impact on asphalt operations.

⁽⁷⁾  Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items, including cash balances.

Management’s Discussion and Analysis 2016

10

4.0 Strategic Plan

The Company’s strategy is to continue to develop a higher return production base, which will further lower its cost structure and drive free cash flow growth.

The Company is building on its thermal expertise through its expanding Lloyd heavy oil thermal developments, the Tucker Thermal Project and the Sunrise Energy Project. The integrated Downstream business maximizes margins from this thermal production while helping shield the Company from volatile differentials. In the Asia Pacific Region, Husky continues to develop its fixed-price natural gas business offshore China and Indonesia, further insulating the Company from commodity price instability. The Western Canada and Atlantic Region portfolios are being rejuvenated with a balance of short to long-term opportunities that provide for higher return production growth.

The Company’s strategic direction by business segment is summarized as follows:

4.1 Upstream

The Company’s heavy oil strategy is focused on expanding its long life, higher return Lloyd thermal production. The Company advanced the development of its heavy oil thermal assets in 2016 with the addition of three new thermal projects with a combined nameplate capacity of 24,500 bbls/day and is currently developing the 10,000 bbls/day Rush Lake 2 project, with expected first production in the first half of 2019. The Company also sanctioned three new Lloyd thermal projects with a total design capacity of about 30,000 bbls/day, which are subject to regulatory approval, with expected first production for all three in 2020.

The Asia Pacific Region consists of the Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 fields on Block 29/26 located offshore China, the Wenchang oil field, the Madura Strait block BD, MDA, MBH, MDK and MAC development fields, three discoveries offshore Indonesia and rights to additional exploration blocks in the South China Sea, offshore Taiwan and offshore Indonesia. The Liwan Gas Project, located approximately 300 kilometres southeast of the Hong Kong Special Administrative Region, is an important component of the Company’s near term production growth strategy and a key step in accessing the burgeoning energy markets in the Hong Kong Special Administrative Region and Mainland China. The Company, and its partner CNOOC, achieved first gas production from the Liwan 3-1 gas field in March 2014 and from the Liuhua 34-2 gas field in December 2014. At the Liwan Gas Project, the second 22-inch subsea pipeline connecting the deepwater pipeline to the central platform has been 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. Negotiations for the sale of gas and liquids from the Liuhua 29-1 gas field are ongoing. At the BD development, 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 Sunrise Energy Project achieved steady production ramp-up, despite wildfires temporarily impacting production in the second quarter of 2016. Total production averaged 25,600 bbls/day (12,800 bbls day net Husky share) in 2016 with annual average 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).

In the Atlantic Region, the Company holds interests in eight Production Licences, eight Exploration Licences and 23 Significant Discovery Areas. Development activity continued to advance at the White Rose core field and its satellites, with first oil achieved at the North Amethyst Hibernia formation well and an additional well brought into production at the South White Rose drill centre. Engineering design and subsurface evaluation work continues at the West White Rose extension to increase capital efficiency and improve resource capture, with the project being considered for sanction in 2017. In the Flemish Pass, the Company holds a 35 percent non-operated working interest in 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.

The Company’s Western Canada resource play strategy is to advance developments in the Spirit River (predominantly Wilrich), Montney and Duvernay formations.

The Infrastructure and Marketing business supports Upstream production while providing integration with the Company’s Downstream assets through optimization of market access. The Company plans to expand export pipeline access and product storage opportunities to enhance market access. 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 Company retains a 35 percent ownership interest and remains the operator of the assets, which will provide the takeaway capacity for another eight heavy oil thermal developments. Strategically, the deal facilitates both the expansion of Husky Lloydminster area production and the expansion of third-party tariff business.

Management’s Discussion and Analysis 2016

11

4.2 Downstream

The Company’s Downstream operations target three primary objectives: increasing feedstock flexibility to bring the best-priced crude to the Company’s refineries, improving flexibility in the range of its products to capitalize on opportunities and enhancing market access to achieve the best returns. The Company’s focused integration strategy helps to capture refined product pricing for its Western Canada heavy oil, bitumen and light oil production and assists in mitigating market volatility.

Downstream operations include upgrading and refining crude oil and marketing gasoline, diesel, jet fuel, asphalt, ethanol and related products in Canada and the United States.

The Company’s strategic plans emphasize safe, reliable, cost effective operations. To enhance crude oil processing optionality at the Lima Refinery, the Company continued to make progress on the crude oil flexibility project targeted for completion in 2018. The project will allow for the processing of up to 40,000 bbls/day of heavy crude oil feedstock from Western Canada, enabling the Lima Refinery to swing between light and heavy crude oil feedstock and strengthening the Company’s integration model. The first stage of the project is now complete and the Refinery can currently process up to 10,000 bbls/day of heavy crude oil feedstock.

At the BP-Husky Toledo Refinery, the Company and its partner completed a feedstock optimization project in 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.

4.3 Financial

The Company is committed to ensuring sufficient liquidity, financial flexibility and access to long-term capital to fund the Company’s growth. The Company maintains undrawn committed term credit facilities with a portfolio of creditworthy financial institutions and other sources of liquidity to provide timely access to funding to supplement cash flow.

The Company intends to continue to maintain a healthy balance sheet to provide financial flexibility. The Company’s target is to maintain a debt to funds from operations ratio of under 2.0 times and a debt to capital employed ratio of under 25 percent, which are both non-GAAP measures (refer to Sections 8.4 and 11.3). The Company is committed to retaining its investment grade credit ratings to support access to debt capital markets. The Company has taken measures to strengthen its financial position and navigate through this commodity down cycle which include, but are not limited to, a reduction of budgeted capital spending, the suspension of the quarterly common share dividend, the sale of royalty interests in Western Canada production, the sale of non-core assets in Western Canada, a strategic disposition of select midstream assets and the continued transition to lower sustaining and higher return Lloyd thermal projects. Refer to Section 8.0 for additional information on the Company’s liquidity and capital resources.

Management’s Discussion and Analysis 2016

12

5.0 Key Growth Highlights

The 2016 Capital Program enabled the Company to advance its near-term profitable growth projects while maintaining prudent capital management in a weak commodity price environment.

5.1 Upstream

Heavy Oil

Heavy Oil Thermal Developments

The Company continued to advance its inventory of heavy oil thermal developments in 2016. These long-life developments are built with modular, repeatable designs and require low sustaining capital once brought online.

The following table lists the design capacity, percentage completion and status for the Company’s near-term heavy oil thermal developments:

Heavy Oil Thermal Developments

Development	Design Capacity (bbls/day)		Percentage Completion			Status	2016 Exit Production (bbls/day) (1)
Edam East		10,000		100	%	On production		14,900
Vawn		10,000		100	%	On production		11,400
Edam West		4,500		100	%	On production		4,200

⁽¹⁾  Exit production is the average production for the month of December.

Total heavy oil thermal production, including the Tucker Thermal Project averaged 84,600 bbls/day in 2016 compared to 59,900 bbls/ day in 2015, a 41 percent increase. The increase is primarily attributed to new production from the Edam East, Vawn, and Edam West heavy oil thermal developments in addition to steady production from the balance of the Company’s other heavy oil thermal developments, including the Tucker Thermal Project.

Total heavy oil thermal production reached an average production of 102,400 bbls/day in December.

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.

Development continues at the 10,000 bbls/day Rush Lake 2 heavy oil thermal development, with first production expected in the first half of 2019.

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 is expected in 2020.

Oil Sands

Sunrise Energy Project

Production from the Sunrise Energy Project averaged 25,600 bbls/day (12,800 bbls/day net Husky share) in 2016. Production was temporarily impacted by the wildfire in the second quarter and averaged approximately 35,000 bbls/day (17,500 bbls/day net Husky share) in December. The Company has introduced higher operating pressures, as approved by the Alberta Energy Regulator (“AER”), contributing to higher steam-oil ratio (“SOR”) in the short term. As a result, the Company expects improved well conformance and production rates over the next two years.

Production is expected to continue to ramp up in 2017 with average annual production in the range of 40,000 to 44,000 bbls/day (20,000 to 22,000 bbls/day net Husky share).

Management’s Discussion and Analysis 2016

13

Asia Pacific Region

China

Block 29/26

Combined gross production from Liwan 3-1 and Liuhua 34-2 averaged 48,800 boe/day (24,800 boe/day net Husky share) in 2016, consisting of gross natural gas production of 224 mmcf/day and NGL production of 11.5 mbbls/day compared to 62,300 boe/day (38,400 boe/day net Husky share) in 2015, consisting of gross natural gas production of 286 mmcf/day and NGL production of 14.6 mbbls/day. The decrease in production in 2016 was due to issues within the buyer’s onshore pipeline network in the first quarter, reduced demand throughout the year and the Company’s share of production volumes reverted back to 49 percent in the second quarter of 2015 following the completion of exploration cost recoveries from the Liwan 3-1 field. The second 22-inch subsea pipeline connecting the deepwater pipeline to the central platform has been 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.

Negotiations for the sale of gas and liquids from the Liuhua 29-1 gas field are ongoing.

Block 15/33

On the 15/33 block located offshore China, the Company is continuing to plan for exploration activities and expects to drill two wells in the 2017-2018 timeframe.

Offshore Taiwan

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

Indonesia

Madura Strait

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 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.

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. 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.

Anugerah

During 2015, the Company acquired two-dimensional and three-dimensional seismic survey data on the contract area. Results from analysis of the data is being evaluated to confirm whether the Company will accept a future drilling commitment.

Atlantic Region

White Rose Field and Satellite Extensions

In 2016, 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 centre 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 project will be considered for sanction in 2017.

Atlantic Exploration

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, Husky 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 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.

Management’s Discussion and Analysis 2016

14

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.

Western Canada Resource Play Development

Oil and Natural Gas Resource Plays

Overall resource play production in Western Canada averaged approximately 34,500 boe/day in 2016, with current development primarily focused on the Ansell multi-zone natural gas resource play.

The Company is pursuing liquids-rich natural gas development opportunities within the existing asset portfolio primarily in the Ansell and Kakwa areas.

5.2 Downstream

Canadian Refined Products

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 of approximately 160 sites. The agreement was approved by Canada’s Competition Bureau in June 2016 and contract closing conditions were met late in the fourth quarter 2016. Progress continues to be made on the implementation of the agreement and the consolidation of the two networks is expected in the second half of 2017.

Lima Refinery

The Company continued work on a crude oil flexibility project in 2016. The project is designed to allow for the processing of up to 40,000 bbls/day of heavy crude oil feedstock from Western Canada providing the Refinery with the ability to swing between light and heavy crude oil feedstock. The first stage of the project was completed in 2016 and the Refinery can currently process up to 10,000 bbls/day of heavy crude oil feedstock. The full scope of the project is expected to be completed in 2018.

BP-Husky Toledo Refinery

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.

Lloydminster Asphalt Expansion

The Company has started pre-FEED work on a potential 30,000 bbls/day expansion of its asphalt processing capacity in Lloydminster with sanctioning expected in 2017. 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.

Management’s Discussion and Analysis 2016

15

6.0 Results of Operations

6.1 Segment Earnings

	Earnings (Loss) before Income Taxes						Net Earnings (Loss)						Capital Expenditures(1)
($ millions)	2016			2015			2016			2015			2016		2015
Upstream
Exploration and Production		(298	)		(5,945	)		(217	)		(4,338	)		872		2,269
Infrastructure and Marketing		1,430			115			1,308			84			54		168
Downstream
Upgrading		241			128			175			93			51		46
Canadian Refined Products		151			231			110			170			52		30
U.S. Refining and Marketing		90			306			57			397			623		425
Corporate		(664	)		(206	)		(511	)		(256	)		53		67
Total		950			(5,371	)		922			(3,850	)		1,705		3,005

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

6.2 Upstream

After Tax Earnings Variance Analysis

($ millions)

Exploration and Production

Exploration and Production Earnings Summary ($ millions)	2016			2015
Gross revenues		4,036			5,374
Royalties		(305	)		(432	)
Net revenues		3,731			4,942
Purchases of crude oil and products		32			41
Production, operating and transportation expenses		1,760			2,076
Selling, general and administrative expenses		232			237
Depletion, depreciation, amortization and impairment		1,815			7,993
Exploration and evaluation expenses		188			447
Gain on sale of assets		(192	)		(17	)
Other – net		53			(34	)
Share of equity investment loss		1			5
Financial items		140			139
Recovery of income taxes		(81	)		(1,607	)
Net earnings (loss)		(217	)		(4,338	)

Management’s Discussion and Analysis 2016

16

Exploration and Production net revenues decreased by $1,211 million in 2016 compared to 2015, primarily due to lower global crude oil benchmark prices, lower crude oil and natural gas production in North America due to the disposition of select legacy Western Canada crude oil and natural gas assets and lower natural gas production in the Asia Pacific Region due to lower demand and the reversion of the Company’s entitlement share of production at Liwan 3-1 to 49 percent, from approximately 76 percent in the second quarter of 2015. The factors affecting the decline in Exploration and Production net revenues were partially offset by higher heavy oil thermal production and lower royalties.

Production, operating, and transportation costs decreased by $316 million in 2016 compared to 2015 primarily due to cost savings initiatives and lower energy costs.

Depletion, depreciation, amortization (“DD&A”) and impairment expense decreased by $6,178 million in 2016 compared to 2015 primarily due to the recognition of a pre-tax impairment charge of $5,181 million on crude oil and natural gas assets in 2015, which reduced the carrying value of the Company’s depletable asset base in 2016 and the recognition of a pre-tax net impairment reversal of $261 million in 2016 related to Western Canada assets.

Exploration and evaluation expenses decreased by $259 million in 2016 compared to 2015. The decrease is primarily due to a $277 million write-down of certain Western Canada resource play assets including associated unfulfilled work commitment penalties in the third quarter of 2015, compared to an $86 million write-off in 2016 primarily due to two unsuccessful exploration wells in the Atlantic Region and a decision by management to not pursue further evaluation of certain Oil Sands assets at this time.

Gain on sale of assets increased by $175 million in 2016 compared to 2015 due to the sale of royalty interests and select legacy Western Canada crude oil and natural gas assets.

Recovery of income taxes decreased by $1,526 million primarily due to a $1,357 million deferred income tax recovery associated with impairment charges recognized on crude oil and natural gas assets located in Western Canada in 2015.

Average Sales Prices Realized

Average Price Realized Crude Oil and NGL ($/bbl)	Average Price Realized Natural Gas ($/mcf)

Average Sales Prices Realized	2016		2015
Crude oil and NGL ($/bbl)
Light & Medium crude oil		52.40		57.55
NGL		38.01		45.88
Heavy crude oil		30.50		37.16
Bitumen		27.63		34.47
Total crude oil and NGL average		35.78		44.18
Natural gas average ($/mcf)		4.40		5.80
Total average ($/boe)		33.08		41.06

The average sales prices realized by the Company declined by 19 percent for crude oil and NGL in 2016 compared to 2015 reflecting significant declines in global crude oil benchmarks.

The average sales prices realized by the Company for natural gas declined by 24 percent in 2016 compared to 2015. The decrease in realized natural gas pricing was primarily due to lower fixed priced natural gas production from the Liwan Gas Project relative to total natural gas production and a price adjustment for natural gas from the Liwan 3-1 and Liuhua 34-2 fields, per the Heads of Agreement (“HOA”) signed by the Company with CNOOC Limited in the third quarter of 2016. The price adjustment under the HOA is effective as of November 2015 and a retroactive adjustment was recognized in the third quarter of 2016. Asia Pacific natural gas production was also lower in 2016 due to reduced buyer demand, temporary production shut-in for the gas buyer’s onshore gas pipeline infrastructure in the first quarter of 2016 and the Company’s share of production volumes reverted back to 49 percent in the second quarter of 2015 following the completion of exploration cost recoveries from the Liwan 3-1 field.

Management’s Discussion and Analysis 2016

17

Daily Gross Production

Production Oil & NGL (mbbls/day)	Production Natural Gas (mmcf/day)	Production Combined (mboe/day)

Daily Gross Production	2016		2015
Crude oil and NGL (mbbls/day)
Western Canada
Light & Medium crude oil		23.4		36.4
NGL		8.0		8.8
Heavy crude oil		54.1		69.1
Bitumen(1)		84.6		59.9
		170.1		174.2
Oil Sands
Sunrise – bitumen		12.8		3.2
Atlantic Region
White Rose and Satellite Fields – light crude oil		28.8		32.1
Terra Nova – light crude oil		4.3		4.7
		33.1		36.8
Asia Pacific Region
Wenchang – light crude oil		6.6		7.3
Liwan and Wenchang – NGL(2)		6.0		9.4
		12.6		16.7
		228.6		230.9
Natural gas (mmcf/day)
Western Canada		442.4		513.9
Asia Pacific Region(2)		113.5		175.1
		555.9		689.0
Total (mboe/day)		321.2		345.7

⁽¹⁾  Bitumen consists of production from heavy oil thermal developments and the Tucker Thermal Project located near Cold Lake, Alberta. Heavy oil thermal average daily gross production was 65.4 mbbls/day and 48.4 mbbls/day for the years ended December 31, 2016 and 2015, respectively.

⁽²⁾  Reported production volumes include Husky’s net working interest production from the Liwan Gas Project (49 percent) and an incremental share of production volumes allocated to Husky for exploration cost recoveries. The incremental share of production volumes ceased during the second quarter of 2015 reflecting the completion of exploration cost recoveries from the Liwan 3-1 field.

Management’s Discussion and Analysis 2016

18

Crude Oil and NGL Production

Crude oil and NGL production decreased by 2.3 mbbls/day or one percent compared to 2015 primarily due to divestitures of select legacy Western Canada crude oil and natural gas assets in 2016 and natural reservoir declines from mature properties in Western Canada and the Atlantic Region. The decreases were partially offset by strong performance from new and existing heavy oil thermal developments and production ramp-up at the Sunrise Energy Project.

Natural Gas Production

Natural gas production decreased by 133.1 mmcf/day or 19 percent compared to 2015. In the Asia Pacific Region, natural gas production decreased by 61.6 mmcf/day due to reduced buyer demand, temporary production shut-in for the connection of a second deepwater pipeline and an unscheduled isolation and temporary repair in the Liwan 3-1 field related to the gas buyer’s onshore gas pipeline infrastructure in the first quarter of 2016. Additionally, the Company’s entitlement share of production volumes reverted back to 49 percent in late May 2015 following the completion of exploration cost recoveries from the Liwan 3-1 field.

In Western Canada, natural gas production decreased by 71.5 mmcf/day primarily due to divestitures of select legacy Western Canada crude oil and natural gas assets, reduced investment, natural reservoir declines from mature properties, strategic shut-ins due to unfavourable economics and third-party pipeline restrictions.

Exploration and Production Revenue Mix (Percentage of Upstream Net Revenues)	2016			2015
Crude oil and NGL
Light & Medium crude oil		32	%		33	%
NGL		5	%		6	%
Heavy crude oil		15	%		18	%
Bitumen		25	%		15	%
Crude oil and NGL		77	%		72	%
Natural gas		23	%		28	%
Total		100	%		100	%

2017 Production Guidance and 2016 Actual

	Guidance		Year ended December 31		Guidance(1)
Gross Production	2017		2016		2016
Canada
Light & Medium crude oil (mbbls/day)		46 - 48		56		66 - 68
NGL (mboe/day)		8 - 9		8		7 - 8
Heavy crude oil & bitumen (mbbls/day)		167 - 173		151		142 - 157
Natural gas (mmcf/day)		345 - 353		442		380 - 430
Canada total (mboe/day)		278 - 288		289		279 - 305
Asia Pacific
Light crude oil (mbbls/day)		5 - 6		7		6 - 7
NGL (mboe/day)		8 - 10		6		7 - 8
Natural gas (mmcf/day)		171 - 182		114		140 - 150
Asia Pacific total (mboe/day)		42 - 46		32		36 - 40
Total (mboe/day)		320 - 335		321		315 - 345

⁽¹⁾  2016 production guidance does not reflect the impact of asset dispositions in Western Canada.

The Company’s total production for the year ended December 31, 2016 was within the production guidance. The Company expects that total production volumes in 2017 will be comparable to 2016. The 2017 production guidance reflects increasing thermal heavy oil production along with increasing bitumen production from the Sunrise Energy Project and initial production from the BD liquids rich gas field in Indonesia. The increases are anticipated to be offset by continued natural declines from mature properties in the Atlantic Region and Western Canada and reflects the Company’s decision to reduce the amount of capital in Western Canada.

Management’s Discussion and Analysis 2016

19

Factors that could potentially impact the Company’s production performance in 2017 include, but are not limited to:

• potential divestment of certain producing crude oil or natural gas properties in Western Canada;

• declines in crude oil and natural gas prices which may result in the decision to temporarily shut-in production or delay capital expenditures;

• increases in crude oil and natural gas prices which may result in the decision to accelerate near-term growth projects;

• performance on recently commissioned facilities, new wells brought onto production and unanticipated reservoir response from existing fields;

• unplanned or extended maintenance and turnarounds at any of the Company’s operated or non-operated facilities, upgrading, refining, pipeline or offshore assets;

• business interruptions due to unexpected events such as severe weather, fires, blowouts, freeze-ups, equipment failures, unplanned and extended pipeline shutdowns and other similar events;

• defaults by contracting parties whose services or facilities are necessary for the Company’s production; and

• operations and assets which are subject to a number of political, economic and socio-economic risks.

Royalties

Royalty rates as a percentage of gross revenues were consistent in 2016 and 2015 at eight percent. Royalty rates in Western Canada averaged seven percent in 2016 compared to nine percent in 2015 primarily due to a higher percentage of production from thermal projects, which are at a lower royalty rate and due to lower commodity prices, which affect royalties on a sliding scale of price sensitivity. Royalty rates in the Atlantic Region averaged 15 percent in 2016 compared to 11 percent in 2015 due to lower eligible royalty costs. Royalty rates in the Asia Pacific Region averaged six percent in 2016 compared to five percent in 2015.

Operating Costs

($ millions)	2016		2015
Western Canada		1,413		1,692
Atlantic Region		224		225
Asia Pacific		92		97
Total		1,729		2,014
Per unit operating costs ($/boe)		14.04		15.14

Total Exploration and Production operating costs were $1,729 million in 2016 compared to $2,014 million in 2015. Total Upstream unit operating costs averaged $14.04/boe in 2016 compared to $15.14/boe in 2015 with the decrease primarily attributable to lower unit operating costs per boe in Western Canada.

Per unit operating costs in Western Canada averaged $14.21/boe in 2016 compared to $16.55/boe in 2015. The decrease in unit operating costs per boe was primarily attributable to cost savings initiatives, lower energy costs and divestitures of higher operating cost assets.

Per unit operating costs in the Atlantic Region averaged $18.48/boe in 2016 compared to $16.76/boe in 2015. The increase in unit operating costs per boe was primarily attributable to a decrease in production.

Per unit operating costs in the Asia Pacific Region averaged $8.01/boe in 2016 compared to $5.78/boe in 2015. The increase in unit operating costs per boe was primarily attributable to lower production at the Liwan Gas Project, partially offset by cost saving initiatives.

Exploration and Evaluation Expenses

($ millions)	2016		2015
Seismic, geological and geophysical		78		103
Expensed drilling		66		297
Expensed land		44		47
Total		188		447

Exploration and evaluation expenses in 2016 were $188 million compared to $447 million in 2015. The decrease in expense drilling is primarily attributable to a $277 million write-down of certain Western Canada resource play assets including associated unfulfilled work commitment penalties in the third quarter of 2015. Included in expensed land and drilling in 2016 is a pre-tax write-off of $86 million mainly related to Oil Sands and Atlantic Region assets. The decrease in seismic, geological and geophysical costs resulted from lower seismic activity across the portfolio.

Management’s Discussion and Analysis 2016

20

Depletion, Depreciation, Amortization and Impairment

DD&A and impairment expense decreased by $6,178 million in 2016 compared to 2015 primarily due to the recognition of a pre-tax impairment charge of $5,181 million on crude oil and natural gas assets, including associated goodwill, located in Western Canada during the third quarter of 2015. The impairment charge reduced the carrying value of the Company’s depletable asset base and resulted in a lower DD&A expense per unit of production in 2016. In 2016, the Company recognized a net pre-tax impairment reversal of $261 million on assets located in Western Canada due to the acceleration of forecasted production and revised operational economics, based on recent production performance and market transactions. Additionally, in 2016, production was lower from the Liwan Gas Project, which carries a higher per unit of production DD&A expense. In 2016, total DD&A excluding impairment averaged $17.67/boe compared to $22.28/boe in 2015.

Operating Netback⁽¹⁾, Unit Operating Costs and DD&A⁽²⁾($/boe)

⁽¹⁾  Operating netback is a non-GAAP measure and is equal to gross revenue less royalties, production and operating costs and transportation costs on a per unit basis. Refer to section 11.3.

⁽²⁾ DD&A excludes impairment and impairment reversals.

Exploration and Production Capital Expenditures

Exploration and Production capital expenditures were lower in 2016 compared to 2015 and reflect the Company’s prudent capital management in a low commodity price environment. Exploration and Production capital expenditures were as follows:

Exploration and Production Capital Expenditures(1)($ millions)	2016		2015
Exploration
Western Canada		18		24
Heavy Oil		6		12
Atlantic Region		18		169
Asia Pacific Region		4		—
		46		205
Development
Western Canada		116		420
Heavy Oil		335		899
Oil Sands		28		264
Atlantic Region		226		379
Asia Pacific Region		114		46
		819		2,008
Acquisitions
Western Canada		—		2
Heavy Oil		7		54
		7		56
		872		2,269

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

Western Canada

During 2016, $134 million (15 percent) was invested in Western Canada conventional and resource plays, compared to $446 million (20 percent) in 2015. Capital expenditures in 2016 relate primarily to sustainment and maintenance activities and the development of the Rainbow Lake NGL project. The decrease in capital expenditures in 2016 compared to 2015 is due to the low commodity price environment.

Management’s Discussion and Analysis 2016

21

Heavy Oil

During 2016, $348 million (40 percent) was invested in Heavy Oil, compared to $965 million (42 percent) in 2015. Capital expenditures in 2016 relate primarily to the development of the Edam East, Edam West and Vawn heavy oil thermal developments in addition to the Colony formation at the Tucker Thermal Project. The decrease in capital expenditures in 2016 compared to 2015 reflects the completion of thermal projects.

Oil Sands

During 2016, $28 million (three percent) was invested in Oil Sands, compared to $264 million (12 percent) in 2015. Capital expenditures in 2016 and 2015 relate primarily to the Sunrise Energy Project. The decrease in capital expenditures in 2016 compared to 2015 reflects the completion of Phase 1 of the Sunrise Energy Project in the third quarter of 2015.

Atlantic Region

During 2016, $244 million (28 percent) was invested in the Atlantic Region, compared to $548 million (24 percent) in 2015. Capital expenditures in 2016 relate primarily to the development of the White Rose extension projects, including North Amethyst and South White Rose satellite fields and further exploration and appraisal drilling in the Flemish Pass Basin. The decrease in capital expenditures in 2016 compared to 2015 reflects the completion of the Bay du Nord delineation program in 2016.

Asia Pacific Region

During 2016, $118 million (14 percent) was invested in the Asia Pacific Region, compared to $46 million (two percent) in 2015. Capital expenditures in 2016 relate primarily to the Liwan Gas Project. The increase in capital expenditures in 2016 compared to 2015 relates primarily to the planned completion of a second subsea pipeline at Liwan.

Onshore drilling activity

The following table discloses the number of wells drilled in Heavy Oil, Oil Sands and Western Canada conventional and resource plays during 2016 and 2015:

	2016				2015
Wells Drilled (wells)(1)	Gross		Net		Gross		Net
Heavy Oil		75		75		87		86
Oil Sands(2)		—		—		28		14
Western Canada conventional and resource plays
Gas Resource		3		2		39		29
Oil Resource		—		—		1		1
Conventional Oil		—		—		6		3
Conventional Gas		—		—		2		—
Enhanced Oil Recovery		—		—		2		2
		78		77		165		135

⁽¹⁾  Excludes Service/Stratigraphic test wells for evaluation purposes.

⁽²⁾  Reflects Husky’s 50 percent working interest in the Sunrise Energy Project.

During 2016, the Company’s onshore drilling was focused primarily on Heavy Oil thermal developments. The decrease of Heavy Oil and Oil Sands drilling and completion activity is due to the completion of three new heavy oil thermal developments in 2016 and first oil at Sunrise Energy Project in 2015. Western Canada resource play drilling and completion activity has been curtailed due to limited capital investment in a low commodity price environment.

Offshore drilling activity

The following table discloses the Company’s offshore Atlantic Region and Asia Pacific Region drilling activity during 2016:

Region	Well	Working Interest	Well Type
Atlantic Region	Bay d’Espoir B-09 (1)	WI 35 percent	Exploration
Atlantic Region	Bay du Loup M-62 (1)	WI 35 percent	Exploration
Atlantic Region	Baccalieu F-89	WI 35 percent	Exploration
Atlantic Region	North Amethyst E-18 12Y	WI 68.875 percent	Development
Atlantic Region	South White Rose Extension J-05 4	WI 68.875 percent	Development
Asia Pacific Region	Madura BD A-1	WI 40 percent	Development
Asia Pacific Region	Madura BD A-2	WI 40 percent	Development
Asia Pacific Region	Madura BD A-3	WI 40 percent	Development
Asia Pacific Region	Madura BD A-4	WI 40 percent	Development

⁽¹⁾  The Bay d’Espoir B-09 and Bay du Loup M-62 exploration wells were fully written off in the second quarter of 2016 as the wells did not encounter economic quantities of hydrocarbons.

Management’s Discussion and Analysis 2016

22

2017 Upstream Capital Expenditures Program

($ millions)
Western Canada	210 - 225
Heavy Oil	685 - 720
Oil Sands	90 -100
Atlantic Region	320 - 335
Asia Pacific Region(1)	230 - 240
Total Upstream capital expenditures	1,535 - 1,620

⁽¹⁾  Includes capital expenditures expected to be incurred by the Husky-CNOOC Madura Ltd. joint venture which are classified as contribution to joint ventures in the investing activities on the Company’s Consolidated Statements of Cash Flows.

The 2017 Upstream capital expenditures program reflects the Company’s prudent capital management in a weak commodity price environment. The Company will continue its transition towards a low sustaining capital business. The Company’s 2017 Upstream capital expenditures program has been designed to remain in balance with funds from operations.

The Company has budgeted $685 - $720 million in Heavy Oil for 2017, primarily for the development of Rush Lake 2 and three newly sanctioned Lloyd thermal projects with total design capacity of about 30,000 bbls/day at Dee Valley, Spruce Lake North and Spruce Lake Central. The three newly sanctioned Lloyd thermal projects are subject to regulatory approval, first production for all three is expected in 2020. The Company is making progress in its strategy to transition a greater percentage of production to long-life heavy oil thermal production and the 2017 Upstream capital expenditures program will continue to build on this momentum.

The Company has budgeted $90 - $100 million in Oil Sands for 2017, primarily for the continued development of the Sunrise Energy Project.

The Company has budgeted $210 - $225 million in Western Canada resource play development for 2017, primarily for development drilling at the Spirit River formation in the Ansell and Kakwa areas.

The Company has budgeted $320 - $335 million in the Atlantic Region for 2017, primarily for the continued development of the main White Rose field and satellite extensions.

The Company has budgeted $230 - $240 million for the Asia Pacific Region in 2017, primarily for the continued development of the Liwan Gas Project and the development of the Madura Strait Block in Indonesia.

Oil and Gas Reserves

The Company’s reserves disclosure was prepared in accordance with Canadian Securities Administrators’ National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) effective December 31, 2016 with a preparation date of January 31, 2017.

Proved and Probable Reserves at December 31:

Light Oil, Medium Oil & NGL (mmbbls)	Heavy Oil (mmbbls)	Bitumen (mmbbls)	Natural Gas (bcf)	Combined (mmboe)

Note: All heavy oil thermal reserves are classified as bitumen.

The Company’s complete oil and gas reserves disclosure, prepared in accordance with NI 51-101 is contained in the Company’s Annual Information Form, which is available at www.sedar.com, and certain supplementary oil and gas reserves disclosure prepared in accordance with U.S. disclosure requirements is contained in the Company’s Form 40-F, which is available at www.sec.gov or on the Company’s website at www.huskyenergy.com.

Management’s Discussion and Analysis 2016

23

Sproule Associates Ltd. (“Sproule”), an independent firm of qualified oil and gas reserves evaluation engineers, was engaged to conduct an audit of the Company’s crude oil, natural gas and NGL reserves estimates. Sproule issued an audit opinion on January 31, 2017 stating that the Company’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 Canadian Oil and Gas Evaluation Handbook.

At December 31, 2016, the Company’s proved oil and gas reserves were 1,224 mmboe, down from 1,324 mmboe at the end of 2015. The Company’s 2016 reserve replacement ratio, defined as net additions divided by total production during the period, was 19 percent excluding economic revisions (15 percent including economic revisions). The 2016 reserves replacement ratio, excluding disposition/ acquisition and economic factors was 92 percent (88 percent including economic factors). Major changes to proved reserves in 2016 included:

• The disposition of a significant portion of the Western Canada assets resulted in a total divestiture of 90 mmboe. Total acquisitions were 5 mmboe, mainly in the Heavy Oil and Gas thermal bitumen area and Western Canada gas plays;

• Technical revisions in Heavy Oil and Gas thermal bitumen projects that resulted in the booking of an additional 47 mmbbls of bitumen in proved reserves;

• An additional 102 bcf of conventional natural gas in proved developed producing reserves was booked from Liwan 3-1; and

• The extension through additional drilling locations and technical revisions at the Tucker Thermal Project that resulted in the booking of an additional 9 mmbbls of bitumen in proved undeveloped reserves.

Proved Plus Probable Reserves and Production at December 31, 2016:

Western Canada (mmbbls)       (bcf)       Atlantic Region       (mmbbls)        China        (mmbbls) (bcf) Indonesia (mmbbls)    (bcf)

Reconciliation of Proved Reserves    

	Canada															International						Total
	Western Canada												Atlantic Region
(forecast prices and costs before royalties)	Light/ Medium Crude Oil & NGL (mmbbls)			Heavy Crude Oil (mmbbls) (1)			Bitumen (mmbbls)(1)			Natural Gas (bcf)			Light Crude Oil (mmbbls)			Light Crude Oil & NGL (mmbbls)			Natural Gas (bcf)			Crude Oil, Bitumen & NGL (mmbbls)			Natural Gas (bcf)			Equivalent Units (mmboe)
Proved reserves
December 31, 2015		117			113			625			1,733			55			24			608			934			2,341			1,324
Technical revisions		3			14			45			40			4			4			102			70			142			94
Acquisitions		—			—			3			8			—			—			—			3			8			5
Dispositions		(29	)		(44	)		—			(105	)		—			—			—			(73	)		(105	)		(90	)
Discoveries, extensions and improved recovery		—			2			11			13			—			—			—			13			13			14
Economic factors		(1	)		(2	)		—			(10	)		—			—			—			(3	)		(10	)		(5	)
Production		(11	)		(20	)		(36	)		(162	)		(12	)		(5	)		(42	)		(84	)		(204	)		(118	)
Proved reserves December 31, 2016		79			63			648			1,517			47			23			668			860			2,185			1,224
Proved and probable reserves December 31, 2016		95			83			1,923			1,940			207			29			926			2,337			2,866			2,815
December 31, 2015		143			147			1,905			2,211			169			32			889			2,396			3,100			2,912

⁽¹⁾  Heavy oil thermal property reserves are classified as bitumen.    

Management’s Discussion and Analysis 2016

24

Reconciliation of Proved Developed Reserves    

	Canada															International						Total
	Western Canada												Atlantic Region
(forecast prices and costs before royalties)	Light/ Medium Crude Oil & NGL (mmbbls)			Heavy Crude Oil (mmbbls) (1)			Bitumen (mmbbls)(1)			Natural Gas (bcf)			Light Crude Oil (mmbbls)			Light Crude Oil & NGL (mmbbls)			Natural Gas (bcf)			Crude Oil, Bitumen & NGL (mmbbls)			Natural Gas (bcf)			Equivalent Units (mmboe)
Proved developed reserves
December 31, 2015		113			108			157			1,390			45			17			339			440			1,729			728
Technical revisions		3			19			19			41			7			4			103			52			144			74
Transfer from proved undeveloped		—			—			19			9			2			7			167			28			176			58
Acquisitions		—			—			—			8			—			—			—			—			8			2
Dispositions		(29	)		(44	)		—			(105	)		—			—			—			(73	)		(105	)		(90	)
Discoveries, extensions and improved recovery		—			2			1			12			—			—			—			3			12			5
Economic factors		(1	)		(2	)		—			(10	)		—			—			—			(3	)		(10	)		(5	)
Production		(11	)		(20	)		(36	)		(162	)		(12	)		(5	)		(42	)		(84	)		(204	)		(118	)
December 31, 2016		75			63			160			1,183			42			23			567			363			1,750			654

⁽¹⁾  Heavy oil thermal property reserves are classified as bitumen.    

Management’s Discussion and Analysis 2016

25

Infrastructure and Marketing

The Company is engaged in the marketing of both its own and other producers’ crude oil, natural gas, NGLs, sulphur and petroleum coke production. The Company owns infrastructure in Western Canada, including pipeline and storage facilities, and has access to capacity on third party pipelines and storage facilities in both Canada and the U.S. The Company is able to capture differences between the two markets by utilizing infrastructure capacity to deliver feedstock acquired in Canada to the U.S. market.

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 HMLP, of which the Company owns 35 percent, PAH owns 48.75 percent and 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.

Infrastructure and Marketing Earnings Summary ($ millions, except where indicated)	2016			2015
Gross revenues		955			1,264
Purchases of crude oil and products		857			1,123
Infrastructure gross margin		98			141
Marketing and other		(88	)		38
Total Infrastructure and Marketing gross margin		10			179
Production, operating and transportation expenses		20			37
Selling, general and administrative expenses		5			7
Depletion, depreciation, amortization and impairment		13			25
Gain on sale of assets		(1,439	)		—
Other – net		(3	)		(5	)
Share of equity investment gain		(16	)		—
Provisions for income taxes		122			31
Net earnings		1,308			84

Infrastructure and Marketing gross revenues and purchases of crude oil products decreased by $309 million and $266 million respectively in 2016 compared to 2015, primarily due to lower commodity prices in the first half of 2016 and the sale of 65 percent of the Company’s ownership interest in select midstream assets.

Marketing and other decreased by $126 million in 2016 compared with 2015 primarily due to crude oil marketing losses from narrowing price differentials between Canada and the United States during 2016. This was partially offset by unrealized gas storage mark-to-market gains as a result of rising forward North American natural gas prices towards the end of 2016.

Gain on sale of assets increased by $1,439 million in 2016 compared with 2015 due to the sale of 65 percent of the Company’s ownership interest in select midstream assets.

Share of equity investment gain increased by $16 million in 2016 compared with 2015 due to the formation of HMLP. Refer to Note 11 of the Consolidated Financial Statements.

Management’s Discussion and Analysis 2016

26

6.3 Downstream

Upgrader

Upgrader Synthetic Crude Sales (mbbls/day)	Upgrader Unit Margin & Operating Costs ($/bbl)

Upgrader Earnings Summary ($ millions, except where indicated)	2016			2015
Gross revenues		1,324			1,319
Purchases of crude oil and products		808			922
Gross margin		516			397
Production, operating and transportation expenses		168			169
Selling, general and administrative expenses		4			4
Depletion, depreciation, amortization and impairment		103			106
Other – net		(1	)		(11	)
Financial items		1			1
Provisions for income taxes		66			35
Net earnings		175			93
Upgrader throughput (mbbls/day)(1)		72.5			69.8
Total sales (mbbls/day)		72.8			69.3
Synthetic crude oil sales (mbbls/day)		55.2			51.1
Upgrading differential ($/bbl)		20.74			18.66
Unit margin ($/bbl)		19.37			15.70
Unit operating cost ($/bbl)(2)		6.33			6.63

⁽¹⁾ Throughput includes diluent returned to the field.

⁽²⁾ Based on throughput.

The Upgrading operations add value by processing heavy crude oil into high value synthetic crude oil and low sulphur distillates. The Upgrader profitability is primarily dependent on the differential between the cost of heavy crude oil feedstock and the sales price of synthetic crude oil.

Upgrader gross revenues increased by $5 million in 2016 compared to 2015 primarily due to higher throughput and sales volumes offset by lower realized prices for synthetic crude oil and low sulphur distillates. The increase in throughput volumes is mainly due to unplanned maintenance to the facility’s coke drums that suspended operations for approximately six weeks in the third quarter of 2015.

Upgrader purchases of crude oil and products decreased by $114 million compared to 2015 primarily due to lower heavy crude oil feedstock costs.

Upgrader gross margin increased by $119 million in 2016 compared to 2015 primarily due to higher average upgrading differentials and the same factors impacting gross revenues and purchases of crude oil and products as discussed above.

Management’s Discussion and Analysis 2016

27

During 2016, the upgrading differential averaged $20.74/bbl, an increase of $2.08/bbl or 11 percent compared to 2015. The differential is equal to Husky Synthetic Blend less Lloyd Heavy Blend. The increase in the upgrading differential was attributable to significantly lower heavy crude oil feedstock costs partially offset by lower realized prices for Husky Synthetic Blend. During 2016, the price of Husky Synthetic Blend averaged $57.54/bbl compared to $61.32/bbl in 2015.

Canadian Refined Products

Canadian Refined Products
Volume (millions of litres/day)	Outlets	Volume per Outlet (thousands of litres/day)

Canadian Refined Products Earnings Summary ($ millions, except where indicated)	2016			2015
Gross revenues		2,301			2,886
Purchases of crude oil and products		1,770			2,281
Gross margin		531			605
Fuel		136			134
Refining		123			150
Asphalt		217			262
Ancillary		55			59
		531			605
Production, operating and transportation expenses		241			238
Selling, general and administrative expenses		43			31
Depletion, depreciation, amortization and impairment		102			103
Gain on sale of assets		(3	)		(5	)
Other – net		(10	)		1
Financial items		7			6
Provisions for income taxes		41			61
Net earnings		110			170
Number of fuel outlets(1)		481			487
Fuel sales volume, including wholesale
Fuel sales (millions of litres/day)		6.6			7.6
Fuel sales per outlet (thousands of litres/day)		11.8			12.5
Refinery throughput
Prince George Refinery (mbbls/day)		9.4			10.7
Lloydminster Refinery (mbbls/day)		27.8			28.1
Ethanol production (thousands of litres/day)		820.6			794.9

⁽¹⁾  Average number of fuel outlets for period indicated.

Canadian Refined Products gross revenues decreased by $585 million in 2016 compared to 2015 primarily due to lower demand driven by a weaker economic environment, resulting in lower refined product prices and lower fuel sales volumes.

Fuel gross margins increased by $2 million in 2016 compared to 2015 primarily due to widening rack to retail differentials partially offset by lower sales volumes.

Management’s Discussion and Analysis 2016

28

Refining gross margins decreased by $27 million in 2016 compared to 2015 primarily due to a planned turnaround at the Prince George Refinery in 2016, which resulted in lower throughput and the need to purchase finished products from third parties to deliver on committed sales volumes. Gross margins also decreased at the Lloydminster and Minnedosa Ethanol plants primarily due to higher grain feedstock costs.

Asphalt gross margins decreased by $45 million in 2016 compared to 2015 primarily due to weather related impacts, which reduced demand and the prevailing price of asphalt.

U.S. Refining and Marketing

Refining Margin U.S. (U.S. $/bbl crude throughput)	Throughput Lima Refinery (mbbls/day)	Toledo Refinery (mbbls/day)

U.S. Refining and Marketing Earnings Summary ($ millions, except where indicated)	2016			2015
Gross revenues		5,995			7,345
Purchases of crude oil and products		5,188			6,455
Gross margin		807			890
Production, operating and transportation expenses		535			474
Selling, general and administrative expenses		13			10
Depletion, depreciation, amortization and impairment		342			333
Other – net		(176	)		(236	)
Financial items		3			3
Provisions for (recovery of ) income taxes		33			(91	)
Net earnings		57			397
Selected operating data:
Lima Refinery throughput (mbbls/day)		138.2			136.1
BP-Husky Toledo Refinery throughput (mbbls/day)(1)		62.2			68.2
Refining margin (U.S. $/bbl crude throughput)		8.94			10.09
Refinery inventory (mmbbls)(2)		10.8			9.8

⁽¹⁾  BP-Husky Toledo Refinery throughput was revised in the first quarter of 2016 to reflect total throughput. Prior periods reflected crude throughput only and have been restated to conform with current presentation.

⁽²⁾  Included in refinery inventory is feedstock and refined products.

U.S. Refining and Marketing gross revenues and purchases of crude oil and products decreased by $1,350 million and $1,267 million, respectively in 2016 compared to 2015, primarily due to lower product and crude pricing, higher cost of RINs, as well as lower sales volumes and throughput at the BP-Husky Toledo Refinery resulting from the scheduled major turnaround earlier in the year. Throughput increased at the Lima Refinery due to unplanned outages in the isocracker and coker units in 2015, partially offset by the scheduled major turnaround in the second quarter of 2016. The isocracker unit was repaired and returned to service in the third quarter of 2016.

Production and operating costs increased by $61 million in 2016 compared to 2015 primarily due to the completion of the scheduled major turnarounds at both the BP-Husky Toledo Refinery and Lima Refinery in 2016.

The Company accrued business interruption and property damage insurance recoveries of $176 million in 2016 associated with the isocracker unit fire at the Lima Refinery, compared to $235 million in 2015, which is reflected in other–net expense. To date, the Company has recorded $411 million in insurance recoveries.

Management’s Discussion and Analysis 2016

29

The Chicago 3:2:1 market crack spread benchmark is based on last in first out (“LIFO”) accounting, which assumes that crude oil feedstock costs are based on the current month price of WTI, while crude oil feedstock costs included in realized margins are based on first in first out (“FIFO”) accounting, which reflects purchases made in previous months. The estimated FIFO impact was an increase in net earnings of approximately $50 million in 2016 compared to a reduction of $130 million in 2015.

In addition, the product slates produced at the Lima and BP-Husky Toledo Refineries contain approximately 10 percent to 15 percent of other products that are sold at discounted market prices compared to gasoline and distillate, which are the standard products included in the Chicago 3:2:1 market crack spread benchmark.

The 2015 recovery of income taxes mainly relates to a deferred income tax recovery of $203 million on the partial payment of the contribution payable to BP-Husky Refining LLC.

Downstream Capital Expenditures

In 2016, Downstream capital expenditures totalled $726 million compared to $501 million in 2015. In Canada, capital expenditures of $103 million were primarily related to the scheduled major turnaround at the Prince George Refinery and projects at the Upgrader.

At the Lima Refinery, $340 million was primarily related to the scheduled major turnaround, a crude oil flexibility project, upgrades to the isocracker unit and various reliability and environmental initiatives. At the BP-Husky Toledo Refinery, capital expenditures totalled $283 million (Husky’s 50 percent share) and were primarily related to the scheduled major turnaround, the feedstock optimization project, facility upgrades and environmental protection initiatives.

6.4 Corporate

Corporate Summary ($ millions) income (expense)	2016			2015
Selling, general and administrative expenses		(247	)		(53	)
Depletion, depreciation, amortization and impairment		(87	)		(84	)
Other – net		(110	)		2
Net foreign exchange gain		13			43
Finance income		12			32
Finance expense		(245	)		(146	)
Recovery of (provisions for) income taxes		153			(50	)
Net loss		(511	)		(256	)

The Corporate segment reported a net loss of $511 million in 2016 compared to a net loss of $256 million in 2015. Selling, general and administrative expenses increased in 2016 primarily due to an increase in stock-based compensation expense which was $33 million in 2016 compared to a recovery of $39 million in 2015 due to declines in the Company’s share price in 2015, as well as higher re-organization costs recognized in 2016 and lower overhead recoveries as a result of lower activity in Western Canada. Other–net expense of $110 million in 2016 relates primarily to losses on the Company’s short term hedging program, which concluded in June 2016. Finance expense increased in 2016 primarily due to a decrease in the amount of capitalized interest compared to 2015 as the Sunrise Energy Project commenced production in 2015. Foreign exchange gain decreased by $30 million due to the items noted below.

Foreign Exchange Summary ($ millions, except exchange rate amounts)	2016		2015
Gains (losses) on translation of U.S. dollar denominated long-term debt		—		(34	)
Gains on non-cash working capital		4		35
Other foreign exchange gains		9		42
Foreign exchange gains		13		43
U.S./Canadian dollar exchange rates:
At beginning of year	U.S. $	0.723	U.S. $	0.862
At end of year	U.S. $	0.745	U.S. $	0.723

Included in other foreign exchange gains are realized and unrealized foreign exchange gains on working capital and intercompany financing. The foreign exchange gains and losses on these items can vary significantly due to the large volume and timing of transactions through these accounts in the period. The Company manages its exposure to foreign currency fluctuations in order to minimize the impact of foreign exchange gains and losses on the Consolidated Financial Statements.

Management’s Discussion and Analysis 2016

30

Consolidated Income Taxes

($ millions)	2016			2015
Provisions for (recovery of ) income taxes		28			(1,521	)
Income taxes paid (received)		(3	)		227

Consolidated income taxes were an expense of $28 million in 2016 compared to an income tax recovery of $1,521 million in 2015. The increase in consolidated income taxes was primarily due to the recognition of gains on the sale of 65 percent of the Company’s ownership interest in select midstream assets and the sale of select Western Canada legacy oil and natural gas assets in 2016. The income tax recovery in 2015 was primarily due to a $1,357 million deferred income tax recovery associated with impairment charges recognized on crude oil and natural gas assets located in Western Canada.

7.0 Risk and Risk Management

7.1 Enterprise Risk Management

The Company’s enterprise risk management program supports decision-making via comprehensive and systematic identification and assessment of risks that could materially impact the results of the Company. Through this framework, the Company builds risk management and mitigation into strategic planning and operational processes for its business units through the adoption of standards and best practices. The Company has developed an enterprise risk matrix to identify risks to its people, the environment, its assets and its reputation, and to systematically mitigate these risks to an acceptable level.

The Company attempts to mitigate its financial, operational and strategic risks to an acceptable level through a variety of policies, systems and processes. The following provides a list of the most significant risks relating to the Company and its operations.

7.2 Significant Risk Factors

Operational, Environmental and Safety Incidents

The Company’s businesses are subject to inherent operational risks in respect to safety and the environment that require continuous vigilance. The Company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner using Husky Operational Integrity Management System (“HOIMS”), its integrated management system that considers environmental requirements and process and occupational safety. Failure to manage the risks effectively could result in potential fatalities, serious injury, interruptions to activities or use of assets, damage to assets, environmental impact or loss of licence to operate. Enterprise risk management, emergency preparedness, business continuity and security policies and programs are in place for all operating areas and are adhered to on an ongoing basis. The Company, in accordance with industry practice, maintains insurance coverage against losses from certain of these risks. Nonetheless, insurance proceeds may not be sufficient to cover all losses, and insurance coverage may not be available for all types of operational risks.

Commodity Price Volatility

Husky’s results of operations and financial condition are dependent on the prices received for its refined products, crude oil, NGL and natural gas production. Lower prices for crude oil, NGLs and natural gas could adversely affect the value and quantity of Husky’s oil and gas reserves. Husky’s reserves include significant quantities of heavier grades of crude oil that trade at a discount to light crude oil. Heavier grades of crude oil are typically more expensive to produce, process, transport and refine into high value refined products. Refining and transportation capacity for heavy crude oil is limited and planned increases of North American heavy crude oil production may create the need for additional heavy oil refining and transportation capacity. Wider price differentials between heavier and lighter grades of crude oil could have a material adverse effect on Husky’s results of operations and financial condition, reduce the value and quantities of Husky’s heavier crude oil reserves and delay or cancel projects that involve the development of heavier crude oil resources. There is no guarantee that pipeline development projects will provide sufficient transportation capacity and access to refining capacity to accommodate expected increases in North American heavy crude oil production.

Prices for refined products and crude oil are based on world supply and demand. Supply and demand can be affected by a number of factors including, but not limited to, actions taken by OPEC, non-OPEC crude oil supply, social conditions in oil producing countries, the occurrence of natural disasters, general and specific economic conditions, technological developments, prevailing weather patterns and the availability of alternate sources of energy.

Management’s Discussion and Analysis 2016

31

Husky’s natural gas production is currently located in Western Canada and the Asia Pacific Region. Western Canada is subject to North American market forces. North American natural gas supply and demand is affected by a number of factors including, but not limited to, the amount of natural gas available to specific market areas either from the well head of existing or accessible conventional or unconventional sources (such as from shale), or from storage facilities, technological developments, prevailing weather patterns, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions.

The natural gas Husky produces in the Asia Pacific Region is sold to specific buyers with long-term contracts. For the Liwan 3-1 gas field, a price profile has been fixed for five years and then will be linked to local benchmark pricing for the years following subject to a floor and ceiling. For the Liuhua 34-2 field, the price is fixed with a single escalation step during the contract delivery period. Natural gas price in North America is affected primarily by supply and demand, as well as by prices for alternative energy sources.

In certain instances, the Company uses derivative commodity instruments and futures contracts on commodity exchanges, including commodity put and call options under a short-term hedging program, to manage exposure to price volatility on a portion of its refined product, oil and gas production, inventory or volumes in long distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and natural gas.

The fluctuations in refined products, crude oil and natural gas prices are beyond the Company’s control and could have a material adverse effect on the Company’s results of operations and financial condition.

Reservoir Performance Risk

Lower than projected reservoir performance on the Company’s key growth projects could have a material adverse effect on the Company’s results of operations, financial condition and business strategy. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets and negatively affect the Company’s reputation, investor confidence and the Company’s ability to deliver on its growth strategy.

In order to maintain the Company’s future production of crude oil, natural gas and NGLs and maintain the value of the reserves portfolio, additional reserves must be added through discoveries, extensions, improved recovery, performance related revisions and acquisitions. The production rate of oil and gas properties tends to decline as reserves are depleted while the associated unit operating costs increase. In order to mitigate the effects of this, the Company must undertake successful exploration and development programs, increase the recovery factor from existing properties through applied technology and identify and execute strategic acquisitions of proved developed and undeveloped properties and unproved prospects. Maintaining an inventory of projects that can be developed depends upon, but is not limited to, obtaining and renewing rights to explore, develop and produce oil and natural gas, drilling success, completion of long lead time capital intensive projects on budget and on schedule and the application of successful exploitation techniques on mature properties.

Restricted Market Access and Pipeline Interruptions

Husky’s results depend upon the Company’s ability to deliver products to the most attractive markets. The Company’s results of operations could be materially adversely effected by restricted market access resulting from a lack of pipeline or other transportation alternatives to attractive markets as well as regulatory and/or other marketplace barriers. Interruptions and restrictions may be caused by the inability of a pipeline to operate, or they can be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. With growing oil production across North America and the limited availability of infrastructure to carry the Company’s products to the marketplace, oil and natural gas transportation capacity is expected to be restricted in the next few years. Restricted market access may potentially have a material adverse effect on the Company’s results of operations, financial condition and business strategy. Unplanned shutdowns and closures of its refineries or Upgrader may limit Husky’s ability to deliver product with a material adverse effect on sales and results of operations.

Security and Terrorist Threats

Security threats and terrorist or activist activities may impact the Company’s personnel, which could result in injury, death, extortion, hostage situations and/or kidnapping, including unlawful confinement. A security threat, terrorist attack or activist incident targeted at a facility, office or offshore vessel/installation owned or operated by the Company could result in the interruption or cessation of key elements of the Company’s operations. Outcomes of such incidents could have a material adverse effect on the Company’s results of operations, financial condition and business strategy.

International Operations

International operations can expose the Company to uncertain political, economic and other risks. The Company’s operations in certain jurisdictions may be adversely affected by political, economic or social instability or events. These events may include, but are not limited to, onerous fiscal policy, renegotiation or nullification of agreements and treaties, imposition of onerous regulation, changes in laws governing existing operations, financial constraints, including currency and exchange rate fluctuations, unreasonable taxation and corrupt behaviour of public officials, joint venture partners or third-party representatives that could result in lost business opportunities for Husky. This could materially adversely affect the Company’s interest in its foreign operations, results of operations and financial condition.

Management’s Discussion and Analysis 2016

32

Major Project Execution

The Company manages a variety of oil and gas projects ranging from upstream to downstream assets. The risks associated with project development and execution, which include the Company’s ability to obtain the necessary environmental and regulatory approvals, changing government regulation and public expectation in relation to the impact on the environment, as well as the risks involved in commissioning and integration of new assets with existing facilities, can impact the economic feasibility of the Company’s projects. Obtaining regulatory approvals can involve significant stakeholder consultation, environmental impact assessments and public hearings. These risks can result in, among other things, cost overruns, schedule delays and decreases in product markets. These risks can also impact the Company’s safety and environmental performance, which could negatively affect the Company’s reputation.

Litigation, Administrative Proceedings and Regulatory Actions

The Company may be subject to litigation, claims, administrative proceedings and regulatory actions, which may be material. Such claims could relate to environmental damage, breach of contract, tax, bribery and employment matters, which could result in an unfavourable decision, including fines, sanctions, monetary damages or the inability to engage in certain operations or transactions. The outcome of such claims can be difficult to assess or quantify and may have a material adverse effect on the Company’s reputation, financial condition and results of operations. The defence to such claims may be costly and could divert management’s attention away from day-to-day operations.

Partner Misalignment

Joint venture partners operate a portion of Husky’s assets in which the Company has an ownership interest. This can reduce Husky’s control and ability to manage risks. Husky is at times dependent upon its partners for the successful execution of various projects. If a dispute with partners were to occur over the development and operation of a project or if partners were unable to fund their contractual share of the capital expenditures, a project could be delayed and the Company could be partially or totally liable for its partner’s share of the project.

Reserves Data and Future Net Revenue Estimates

The reserves data contained or referenced in the MD&A represent estimates only. The accurate assessment of oil and gas reserves is critical to the continuous and effective management of the Company’s upstream assets. Reserves estimates support various investment decisions about the development and management of oil and gas properties. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flow therefrom are based upon a number of variable factors and assumptions, such as product prices, future operating and capital costs, historical production from the properties and the effects of regulation by government agencies, including with respect to royalty payments, all of which may vary considerably from actual results. All such estimates are to some degree uncertain, and classifications of reserves are only attempts to define the degree of uncertainty involved. All reserves estimates involve a degree of ambiguity and, at times, rely on indirect measurement techniques to estimate the size and recoverability of the resource. While new technologies have increased the accuracy of these techniques, there remains the potential for human or systemic error in recording and reporting the magnitude of the Company’s oil and gas reserves. For those reasons, the Company’s estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom may differ substantially from actual results. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets and could have a material adverse effect on the Company’s results of operations, financial condition, and ability to deliver on its growth business strategy.

Government Regulation

Given the scope and complexity of Husky’s operations, the Company is subject to regulation and intervention by governments at the federal, provincial, state and municipal levels in the countries in which it conducts its operations or exploratory activities. As these governments continually balance competing demands from different interest groups and stakeholders, the Company recognizes that the magnitude of regulatory risks has the potential to change over time. Changes in government policy, legislation or regulation could impact the Company’s existing and planned projects as well as impose costs of compliance and increase capital expenditures and operating expenses. Examples of the Company’s regulatory risks include, but are not limited to, uncertain or negative interactions with governments, uncertain energy policies, uncertain climate policies, uncertain environmental and safety policies, penalties, taxes, royalties, government fees, reserves access, limitations or increases in costs relating to the exportation of commodities, restrictions on the acquisition of exploration and production rights and land tenure, expropriation or cancellation of contract rights, limitations on control over the development and abandonment of fields and loss of licences to operate.

Environmental Regulation

Changes in environmental regulation could have a material adverse effect on Husky’s financial condition and results of operations by requiring increased capital expenditures and operating costs or by impacting the quality, formulation or demand of products, which may or may not be offset through market pricing.

The scope and complexity of changes in environmental regulation make it challenging to forecast the potential impact to Husky. Husky has made projections of the impact of scenarios involving certain potential laws and regulations relating to climate change. Husky engages in dialogue on proposed changes, both directly and through industry associations, with the goal of ensuring the Company’s interests are recognized and Husky is sufficiently prepared to fully comply when new regulations come into force.

Management’s Discussion and Analysis 2016

33

Husky anticipates further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, increased compliance costs and approval delays for critical licences and permits, which could have a material adverse effect on Husky’s financial condition and results of operations through increased capital and operating costs.

Climate Change Regulation

The Company continues to monitor international and domestic efforts to address climate change, including international low carbon fuel standards and regulations and emerging regulations in the jurisdictions in which the Company operates.

The Alberta Climate Leadership Plan is expected to be implemented starting in 2017. This plan includes an economy wide carbon levy, rising to $30/ton in 2018 as well as a Carbon Competitiveness Regulation that will manage emissions at large final emitting facilities (“LFEs”) including the Ram River Gas Plant, Tucker Thermal Facility and Sunrise Energy Project. The regulations under this plan are currently under development and will cover all of the Company’s assets in Alberta. These regulations may materially adversely affect the Company’s results of operations in the province.

Climate change regulations to be developed in Saskatchewan will have to meet equivalency standards with the Canadian federal government and may materially adversely affect the Company’s results of operations in the province.

The cost of compliance with British Columbia’s $30 per ton carbon tax and the Renewable and Low Carbon Fuel Requirements Regulation may become material. Additionally, future regulations in support of British Columbia’s commitment under its Climate Leadership Plan may materially adversely affect the Company’s results of operations in British Columbia.

The Manitoba Climate Change and Green Economy Action Plan implementation may materially adversely affect Husky’s results of operations in Manitoba.

The Federal Government of Canada has announced its intention to commence developing a new federal climate change plan in consultation with the provinces. It is not clear how this new plan will be structured and what impacts it will have on Husky’s results of operations. Climate change regulations may become more onerous over time as governments implement policies to further reduce GHG emissions. Although the impact of emerging regulations is uncertain, they could have a material adverse effect on the Company’s financial condition and results of operations through increased capital and operating costs and change in demand for refined products.

The Company’s U.S. refining business may be materially adversely affected by the implementation of the EPA’s climate change rules or by future U.S. GHG legislation that applies to the oil and gas industry or the consumption of petroleum products. Such legislation or regulation could require the Company’s U.S. refining operations to significantly reduce emissions and/or purchase allowances, which may have a material adverse effect on the Company’s financial condition and results of operations through increased capital and operating costs and change in demand for refined products.

The U.S. RFS program, through the U.S. EPA specified renewable volume obligation (“RVO”), requires refiners to add annually increasing amounts of renewable fuels to their petroleum products or to purchase RINs in lieu of such blending. Due to regulatory uncertainty and in part due to the U.S. fuel supply reaching the “blend wall” (the 10% limit prescribed by most automobile warranties), the price and availability of RINs has been volatile.

The Company complies with the RFS program in the US by blending renewable fuels manufactured by third parties and by purchasing RINs on the open market. The Company cannot predict the future prices of RINs and renewable fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. The Company’s financial position and results of operations could be adversely affected if it is unable to pass the costs of compliance on to its customers and if the Company pays significantly higher prices for RINs or blendstocks to comply with the RFS mandated standards.

Competition

The energy industry is highly competitive with respect to gaining access to the resources required to increase oil and gas reserves and production and gain access to markets. The Company competes with others to acquire prospective lands, retain drilling capacity and field operating and construction services, obtain sufficient pipeline and other transportation capacity, gain access to and retain adequate markets for its products and services and gain access to capital markets. The Company’s ability to successfully complete development projects could be adversely affected if it is unable to acquire economic supplies and services due to competition. Subsequent increases in the cost of or delays in acquiring supplies and services could result in uneconomic projects. The Company’s competitors comprise all types of energy companies, some of which have greater resources.

General Economic Conditions

General economic conditions may have a material adverse effect on the Company’s results of operations and financial condition. A decline in economic activity will reduce demand for petroleum products and adversely affect the price the Company receives for its commodities. The Company’s cash flow could decline, assets could be impaired, future access to capital could be restricted and major development projects could be delayed or abandoned.

Management’s Discussion and Analysis 2016

34

Cost or Availability of Oil and Gas Field Equipment

The cost or availability of oil and gas field equipment may adversely affect the Company’s ability to undertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including land and offshore drilling rigs, land and offshore geological and geophysical services, engineering and construction services and construction materials. These materials and services may not be available when required at reasonable prices.

Climatic Conditions

Extreme climatic conditions may have material adverse effects on results of operations. Weather and climate affect demand, and therefore, the predictability of the demand for energy is affected to a large degree by the predictability of weather and climate. In addition, the Company’s exploration, production and construction operations, or disruptions to the operations of major customers or suppliers, can be affected by extreme weather. This may result in cessation or diminishment of production, delay of exploration and development activities or delay of plant construction. All of these could potentially cause material adverse effects on the Company’s results of operations and financial condition.

The Company operates in some of the harshest environments in the world, including offshore in the Atlantic Region. Climate change may increase severe weather conditions in these locations including winds, flooding and variable temperatures, which are contributing to the melting of Northern ice and increased creation of icebergs. Icebergs off the coast of Newfoundland and Labrador may threaten offshore oil production facilities, causing damage to equipment and possible production disruptions, spills, asset damage and human impacts. The Company has in place a number of policies to protect people, equipment and the environment in the event of extreme weather conditions and ice melt conditions.

The Company’s Atlantic Region business unit has a robust ice management program, which uses a range of resources including a dedicated ice surveillance aircraft, as well as synergistic relationships with government agencies including Environment Canada, the Coast Guard and Canadian Ice Service. Regular ice surveillance flights commence in February and continue until the threat has abated. In addition, Atlantic Region operators employ a series of supply and support vessels to actively manage ice and icebergs. These vessels are equipped with a variety of ice management tools including towing ropes, towing nets and water cannons. The Company also maintains a series of ad-hoc relationships with contractors, allowing the quick mobilization of additional resources as required.

Financial Controls

While the Company has determined that its disclosure controls and procedures and internal controls over financial reporting are effective, such controls can only provide reasonable assurance with respect to financial statement preparation and disclosure. Failure to prevent, detect and correct misstatements could have a material adverse effect on the Company’s results of operations and financial condition.

Cybersecurity Threats

As an oil and gas producer, the Company’s ability to operate effectively is dependent upon developing and maintaining information systems and infrastructure that support the financial and general operating aspects of the business. Concurrently, the oil and gas industry has become the subject of increased levels of cybersecurity threats.

The Company has security measures, policies and controls designed to protect and secure the integrity of its information technology systems. The Company takes a proactive approach by continuing to invest in technology, processes and people to help minimize the impact of the changing cyber landscape and enhance the Company’s resilience to cyber incidents. However, cybersecurity threats frequently change and require ongoing monitoring and detection capabilities. Such cybersecurity threats include unauthorized access to information technology systems due to hacking, viruses and other causes for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption by third parties. Cyber-attacks could result in the loss or exposure of confidential information related to retail credit card information, personnel files, exploration activities, corporate actions, executive officer communications and financial results. The significance of any such event is difficult to quantify, but if the breach is material in nature, it could adversely affect the financial performance of the Company, its operations, its reputation and standing and expose it to regulatory consequences and claims of third-party damage, all of which could materially adversely affect the Company’s results of operations and financial condition if the situation is not resolved in a timely manner, or if the financial impact of such adverse effects is not alleviated through insurance policies.

Although to date the Company has not experienced any material losses relating to cyber attacks or other information security breaches, there can be no assurance that the Company will not incur such losses in the future. The Company’s risk and exposure to these matters cannot be fully mitigated because of, among other things, the evolving nature of these threats. The Audit Committee of the Company’s Board of Directors has oversight of the Company’s risk mitigation strategies related to cybersecurity.

Skilled Workforce Shortage

Successful execution of Husky’s strategy is dependent on ensuring our workforce possesses the appropriate skill level. There is a risk that the Company may have difficulty attracting and retaining personnel with the required skill levels. Failure to attract and retain personnel with the required skill levels could have a material adverse effect on the Company’s results of operations.

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7.3 Financial Risks

The Company’s financial risks are largely related to commodity price risk, foreign currency risk, interest rate risk, counterparty credit risk, liquidity risk and credit rating risk. From time to time, the Company uses derivative financial instruments to manage its exposure to these risks. These derivative financial instruments are not intended for trading or speculative purposes.

Fair Value of Financial Instruments

The Company’s financial assets and liabilities that are recorded at fair value on a recurring basis have been categorized into one of three categories based upon the fair value hierarchy. Level 1 fair value measurements are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair value measurements of assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant outputs are observable, either directly or indirectly. Level 3 fair value measurements are based on inputs that are unobservable and significant to the overall fair value measurement.

The Company’s financial instruments include cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, short-term debt, long-term debt, contribution payable, inventories measured at fair value, long-term income tax receivable, portions of other assets and other long-term liabilities.

For the year ended December 31, 2016, the Company recognized a $39 million unrealized loss on its crude oil and natural gas risk management positions which were recorded in marketing and other. In addition, the Company recognized a $10 million realized gain recorded in net foreign exchange and a $121 million realized loss on a short-term corporate hedging program recorded in other-net. Refer to Note 24 to the 2016 Consolidated Financial Statements.

Commodity Price Risk

In certain instances, the Company uses derivative commodity instruments and futures contracts on commodity exchanges, including commodity put and call options under a short-term hedging program, to manage exposure to price volatility on a portion of its refined product, oil and gas production, and inventory or and volumes in long distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and natural gas. For the year ended December 31, 2016, the Company incurred a realized loss of $121 million on a short-term corporate hedging program, which is recorded in other-net in the Consolidated Statements of Income (Loss). The hedging program concluded in June 2016.

The Company’s results will be impacted by a decrease in the price of crude oil and natural gas inventory. The Company has crude oil inventories that are feedstock, held at terminals or part of the in-process inventories at its refineries and at offshore sites. The Company also has natural gas inventory that could have an impact on earnings based on changes in natural gas prices. All these inventories are subject to a lower of cost or net realizable value test on a monthly basis.

Foreign Currency Risk

The Company’s results are affected by the exchange rates between various currencies including the Canadian and U.S. dollars. The majority of the Company’s expenditures are in Canadian dollars while the majority of the Company’s revenues are received in U.S. dollars from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in the Company’s U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. The fluctuations in exchange rates are beyond the Company’s control and could have a material adverse effect on the Company’s results of operations and financial condition.

The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. dollar denominated revenue to hedge against these potential fluctuations. The Company also designates its U.S denominated debt as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency.

Interest Rate Risk

Interest rate risk is the impact of fluctuating interest rates on financial condition. In order to manage interest rate risk and the resulting interest expense, the Company mitigates some of its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt through the use of its credit facilities and various financial instruments. The optimal mix maintained will depend on market conditions. The Company may also enter into interest rate swaps from time to time as an additional means of managing current and future interest rate risk.

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Counterparty Credit Risk

Credit risk represents the financial loss that the Company would suffer if the Company’s counterparties in a transaction fail to meet or discharge their obligation to the Company. The Company actively manages this exposure to credit and contract execution risk from both a customer and a supplier perspective. Internal credit policies govern the Company’s credit portfolio and limit transactions according to a counterparty’s and a supplier’s credit quality. Counterparties for financial derivatives transacted by the Company are generally major financial institutions or counterparties with investment grade credit ratings.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. The Company’s process for managing liquidity risk includes ensuring, to the extent possible, that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facilities and the availability to raise capital from various debt and equity capital markets under its shelf prospectuses. The availability of capital under its shelf prospectuses is dependent on market conditions at the time of sale.

Credit Rating Risk

Credit ratings affect Husky’s ability to obtain short-term and long-term financing and the cost of such financing. Additionally, the ability of Husky to engage in ordinary course derivative or hedging transactions and maintain ordinary course contracts with customers and suppliers on acceptable terms depends on Husky’s credit ratings. A reduction in the current rating on Husky’s debt by one or more of its rating agencies, particularly a downgrade below investment grade ratings, or a negative change in Husky’s ratings outlook could adversely affect Husky’s cost of financing and its access to sources of liquidity and capital. Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings accorded to Husky’s securities by the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

The Company is committed to retaining investment grade credit ratings to support access to capital markets and currently has the following credit ratings:

	Standard and Poor’s Rating Services	Moody’s Investor Service (“Moody’s”)	Dominion Bond Rating Services Limited
Outlook/Trend	Stable	Stable	Stable
Senior Unsecured Debt	BBB+	Baa2	A(low)
Series 1 Preferred Shares	P-2(low)		Pfd-2(low)
Series 2 Preferred Shares	P-2(low)		Pfd-2(low)
Series 3 Preferred Shares	P-2(low)		Pfd-2(low)
Series 5 Preferred Shares	P-2(low)		Pfd-2(low)
Series 7 Preferred Shares	P-2(low)		Pfd-2(low)
Commercial Paper			R-1(low)

Debt Covenants

The Company’s credit facilities include financial covenants, which include a debt to capital covenant. If the Company does not comply with the covenants under these credit facilities, there is a risk that repayment could be accelerated.

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8.0 Liquidity and Capital Resources

8.1 Summary of Cash Flow

Cash Flow Summary ($ millions)	2016			2015
Cash flow
Operating activities		1,971			3,760
Financing activities		(1,362	)		(210	)
Investing activities		632			(4,817	)

Cash Flow from Operating Activities

Cash flow generated from operating activities was $1,971 million in 2016 compared to $3,760 million in 2015. The decrease was primarily due to lower realized crude oil and North American natural gas prices, a reduction to the fixed priced natural gas from Asia Pacific and lower U.S. market crack spreads, partially offset by lower operating costs due to cost savings initiatives and increased production from new and existing heavy oil thermal developments.

Cash Flow used for Financing Activities

Cash flow used for financing activities was $1,362 million in 2016 compared to $210 million in 2015. In 2016, cash flow used for financing activities was primarily used for the net repayment of $520 million of short-term debt and $768 million of long term debt, compared to to the net repayment of $175 million of short-term debt and net issuance of $949 million of long term debt in 2015. In 2015, the Company paid $1,167 million on dividends on common shares, the common share dividends were subsequently suspended in late 2015 and the Company did not pay cash dividends on common shares in 2016.

Cash Flow from (used for) Investing Activities

Cash flow generated from investing activities was $632 million in 2016 compared to cash flow used for investing activities of $4,817 million in 2015. The increase was primarily due to total cash proceeds from asset sales of $2,935 million in 2016 from the sale of 65 percent of the Company’s ownership interest in select midstream assets, the sale of royalty interests representing approximately 1,700 boe/day of Western Canada Production and the sale of approximately 30,200 boe/day of select legacy Western Canada crude oil and natural gas assets combined with the decrease of capital expenditures in 2016. The cash flow used for investing activities in 2015 also included $1,363 million of a partial payment of the contribution payable to BP-Husky Refining LLC, compared to $193 million in 2016.

8.2 Working Capital Components

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2016, Husky’s working capital was $1,125 million compared to a deficiency of $922 million at December 31, 2015. A reconciliation of Husky’s working capital (deficiency) is as follows:

($ millions)	December 31, 2016			December 31, 2015			Change
Cash and cash equivalents		1,319			70			1,249
Accounts receivable		1,036			1,014			22
Income taxes receivable		186			312			(126	)
Inventories		1,558			1,247			311
Prepaid expenses		135			271			(136	)
Restricted cash		84			—			84
Accounts payable and accrued liabilities		(2,226	)		(2,527	)		301
Short-term debt		(200	)		(720	)		520
Long-term debt due within one year		(403	)		(277	)		(126	)
Contribution payable		(146	)		(210	)		64
Asset retirement obligations		(218	)		(102	)		(116	)
Net working capital (deficiency)		1,125			(922	)		2,047

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The increase in cash was primarily due to proceeds from the sale of royalty interests representing approximately 1,700 boe/day of Western Canada production, the sale of 65 percent of the Company’s ownership interest in select midstream assets and the sale of approximately 30,200 boe/day of legacy Western Canada crude oil and natural gas assets in 2016. Fluctuations in accounts receivable and accounts payable are due to the timing of settlements in 2016 compared to 2015. The decrease in income taxes receivable is due to timing of expected tax refunds. The increase in inventories is primarily due to higher U.S. refining throughputs in the fourth quarter of 2016 compared to 2015.

The decrease in short-term debt is due to the the net repayment of $520 million of short-term debt in 2016 compared to the net repayment of $175 million of short-term debt in 2015.

8.3 Sources of Liquidity

Liquidity describes a company’s ability to access cash. Sources of liquidity include funds from operations, proceeds from the issuance of equity, proceeds from the issuance of short and long-term debt, availability of short and long-term credit facilities and proceeds from asset sales. Since the Company operates in the upstream oil and gas industry, it requires significant cash to fund capital programs necessary to maintain or increase production, develop reserves, acquire strategic oil and gas assets and repay maturing debt.

During times of low oil and gas prices, a portion of capital programs can generally be deferred. However, due to the long cycle times and the importance to future cash flow in maintaining the Company’s production, it may be necessary to utilize alternative sources of capital to continue the Company’s strategic investment plan during periods of low commodity prices. As a result, the Company frequently evaluates the options available with respect to sources of short and long-term capital resources. The Company believes that it has sufficient liquidity to sustain its operations, fund capital programs and meet non-cancellable contractual obligations and commitments in the short and long-term principally by cash generated from operating activities, cash on hand, the issuance of equity, the issuance of debt, borrowings under committed and uncommitted credit facilities and cash proceeds from asset sales. The Company is continually examining its options with respect to sources of long and short-term capital resources to ensure it retains financial flexibility.

At December 31, 2016, the Company had the following available credit facilities:

Credit Facilities

($ millions)	Available		Unused
Operating facilities(1)		670		292
Syndicated credit facilities(2)		4,000		3,800
		4,670		4,092

⁽¹⁾ Consists of demand credit facilities and letter of credit.

⁽²⁾ Commercial paper outstanding is supported by the Company’s syndicated credit facilities.

At December 31, 2016, the Company had $4,092 million of unused credit facilities of which $3,800 million are long-term committed credit facilities and $292 million are short-term uncommitted credit facilities. A total of $378 million of the Company’s short-term uncommitted borrowing credit facilities was used in support of outstanding letters of credit and $200 million of the Company’s long-term committed borrowing credit facilities was used in support of commercial paper. At December 31, 2016, the Company had no direct borrowing against committed credit facilities. The Company’s ability to renew existing bank credit facilities and raise new debt is dependent upon maintaining an investment grade debt rating and the condition of capital and credit markets. Credit ratings may be affected by the Company’s level of debt, from time to time.

The Company’s share capital is not subject to external restrictions; however, the Company’s leverage covenant under both of its revolving syndicated credit facilities was modified to a debt to capital covenant calculated as total debt (long-term debt including long-term debt due within one year and short-term debt) and certain adjusting items specified in the agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the agreement. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2016 and assesses the risk of non-compliance to be low.

The Sunrise Oil Sands Partnership has an unsecured demand credit facility of $10 million available for general purposes. The Company’s proportionate share is $5 million. There were no amounts drawn on this demand credit facility at December 31, 2016.

On February 23, 2015, the Company filed a universal short form base shelf prospectus with applicable securities regulators in each of the provinces of Canada (the “Canadian Shelf Prospectus”) that 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. During the 25-month period that the Canadian Shelf Prospectus is effective, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement.

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On March 6, 2015, the Company’s $1.63 billion and $1.60 billion revolving syndicated credit facilities were each increased to $2.0 billion. The terms of the revolving syndicated credit facilities remain unchanged.

On March 12, 2015, the Company issued eight million Cumulative Redeemable Preferred Shares, Series 5 (the “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. Net proceeds after share issue costs were $195 million. 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. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.57 percent. Holders of Series 5 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 6 (the “Series 6 Preferred Shares”), subject to certain conditions, on March 31, 2020 and on March 31 every five years thereafter. Holders of the Series 6 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.57 percent. Net proceeds from the Series 5 Preferred Shares was used for general corporate purposes, which included, among other things, the partial repayment of bank debt incurred by the Company to fund early payment of U.S. $1 billion of the Company’s net capital contribution payable with BP-Husky Refining LLC.

On March 12, 2015, the Company repaid the maturing 3.75 percent 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. Net proceeds from the offering was used for general corporate purposes, which included, among other things, the partial repayment of bank debt incurred by the Company to fund early payment of U.S. $1 billion of the Company’s net capital contribution payable with BP-Husky Refining LLC.

On June 17, 2015, the Company issued six million Cumulative Redeemable Preferred Shares, Series 7 (the “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. Net proceeds after share issue costs were $145 million. 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. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.52 percent. Holders of the Series 7 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 8 (the “Series 8 Preferred Shares”), subject to certain conditions, on June 30, 2020 and on June 30 every five years thereafter. Holders of the Series 8 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.52 percent. Net proceeds from the Series 7 Preferred Shares was used for general corporate purposes, which included, among other things, the partial repayment of bank debt incurred by the Company to fund capital expenditures for the advancement of near term heavy oil thermal projects.

On December 22, 2015, the Company filed a universal short form base shelf prospectus (the “U.S. Shelf Prospectus”) with the Alberta Securities Commission and a related U.S. registration statement containing the U.S. Shelf Prospectus with the SEC that 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 United States up to and including January 22, 2018. During the 25-month period that the U.S. Shelf Prospectus and the related U.S registration statement are effective, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement.

In March 2016, holders of 1,564,068 Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) exercised their option to convert their shares, on a one-for-one basis, to Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”) and receive a floating rate quarterly dividend. The dividend rate applicable to the Series 2 Preferred Shares for the three month period commencing September 30, 2016 to, but excluding, December 31, 2016, is equal to the sum of the Government of Canada 90 day treasury bill rate on August 31, 2016 plus 1.73 percent, being 2.242 percent. The floating rate quarterly dividend applicable to the Series 2 Preferred Shares will be reset every quarter. The dividend rate applicable to the Series 1 Preferred Shares for the five year period commencing March 31, 2016, to, but excluding, March 31, 2021 is equal to the sum of the Government of Canada five year bond yield on March 1, 2016 plus 1.73 percent, being 2.404 percent. Both rates were calculated in accordance with the articles of amendment of the Company creating the Series 1 Preferred Shares and Series 2 Preferred Shares dated March 11, 2011.

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 the leverage covenant under both of its revolving syndicated credit facilities ($2.0 billion maturing June 19, 2018 and $2.0 billion maturing March 9, 2020) was modified to a debt to capital covenant. At December 31, 2016 the Company was in compliance with the syndicated credit facility covenants and assesses the risk of non-compliance to be low.

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On November 15, 2016, the Company repaid the 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.

The Company has $1.9 billion in unused capacity under the Canadian Shelf Prospectus and U.S. $3.0 billion in unused capacity under the U.S. Shelf Prospectus and related U.S. registration statement as at December 31, 2016. The ability of the Company to utilize the capacity under its Canadian Shelf Prospectus and U.S. Shelf Prospectus and related U.S. registration statement is subject to market conditions at the time of sale.

Net debt

Net debt is calculated as total debt less cash and cash equivalents. At December 31, 2016, the Company had total debt of $5,339 million and cash and cash equivalents of $1,319 million compared to total debt of $6,756 million and cash and cash equivalents of $70 million at December 31, 2015. The Company’s net debt decreased by $2,666 million when compared to December 31, 2015:

Net debt ($ millions)	December 31, 2016			December 31, 2015
Net debt at beginning of period		(6,686	)		(4,025	)
Change in net debt due to:
Funds from operations(1)		2,076			3,329
Capital expenditures		(1,705	)		(3,005	)
Cash dividends paid on common and preferred shares		(27	)		(1,203	)
Change in non-cash working capital		(227	)		498
Proceeds from asset sales		2,935			122
Net proceeds from issuance of preferred shares		—			340
Effect of exchange rates on cash and cash equivalents		8			70
Effect of exchange rates on long-term debt		130			(692	)
Income taxes received (paid)		3			(227	)
Net interest paid		(344	)		(320	)
Contribution payable		(193	)		(1,363	)
Other		10			(210	)
		2,666			(2,661	)
Net debt at end of period		(4,020	)		(6,686	)

⁽¹⁾  Funds from operations is a non-GAAP measure. Refer to Section 11.3 for a reconciliation to the GAAP measure.

During the years ended December 31, 2016 and 2015, the Company’s capital expenditures were funded by funds from operations. The Company’s funds from operations is dependent on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates. Management prepares capital expenditure budgets annually which are regularly monitored and updated to adapt to changes in market factors. In addition, the Company requires authorizations for capital expenditures on projects, which assists with the management of capital.

During the year ended December 31, 2016, the Company issued common stock dividends of $296 million on January 11, 2016, on account of common share dividends declared for the third quarter of 2015. The common share dividend was suspended by the Board of Directors in the fourth quarter of 2015. This initiative supports long-term value maximization while providing further financial flexibility for the Company to achieve its business and financial objectives. The Board of Directors carefully considers numerous factors, including earnings, commodity price outlook, future capital requirements and the financial condition of the Company. The Board will continue to review the Company’s common share dividend policy on a quarterly basis. During the year ended December 31, 2016, there were no common share dividends declared compared to $1,181 million during 2015.

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8.4 Capital Structure

Capital Structure	December 31, 2016
($ millions)	Outstanding		Available(1)
Total debt		5,339		4,092
Common shares, preferred shares, retained earnings and other reserves		17,616

⁽¹⁾ Total debt available includes committed and uncommitted credit facilities.

The Company’s objectives when managing capital are to maintain a flexible capital structure, which optimizes the cost of capital at acceptable risk, and to maintain investor, creditor and market confidence to sustain the future development of the business. The Company manages its capital structure and makes adjustments as economic conditions and the risk characteristics of its underlying assets change. The Company considers its capital structure to include shareholders’ equity and debt, which was $23.0 billion at December 31, 2016 (December 31, 2015 – $23.3 billion). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise debt and/or adjust its capital spending to manage its current and projected debt levels.

The Company monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of debt to capital employed and debt to funds from operations (refer to section 11.3). The Company’s objective is to maintain a debt to capital employed target of less than 25 percent and a debt to funds from operations ratio of less than 2.0 times. At December 31, 2016, debt to capital employed was 23.2 percent (December 31, 2015 – 28.9 percent) and debt to funds from operations was 2.6 times (December 31, 2015 – 2.0 times).

The decrease in the Company’s debt to capital employed as at December 31, 2016 is due to proceeds received from the sale of 65 percent of the Company’s ownership interest in select midstream assets in the third quarter of 2016 and the sale of royalty interests representing approximately 1,700 boe/day of Western Canada production and the sale of approximately 30,200 boe/day of legacy Western Canada crude oil and natural gas assets in 2016, which were partially used for the repayment of debt. The higher debt to funds from operations ratio as at December 31, 2016 reflects the impact of lower global crude oil and North American natural gas benchmark pricing, which resulted in significantly lower funds from operations. To facilitate the management of these ratios, the Company prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors.

The Company has taken measures to strengthen its financial position and navigate through this commodity down cycle which include, but are not limited to, a reduction of budgeted capital spending, the suspension of the quarterly common share dividend, the sale of royalty interests in Western Canada production, the sale of non-core assets in Western Canada, a strategic disposition of select midstream assets and the continued transition to lower sustaining and higher return Lloyd thermal projects.

Divestitures

Pipeline and Terminals

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 HMLP, of which the Company owns 35 percent, PAH owns 48.75 percent and 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.

Upstream Exploration and Production - Western Canada

In 2016, the Company completed the sale of royalty interests representing approximately 1,700 boe/day of Western Canada production for gross proceeds of $165 million and the sale of approximately 30,200 boe/day of legacy crude oil and natural gas assets in Western Canada for gross proceeds of $1.12 billion.

Use of Proceeds

Cash proceeds from the dispositions allowed the Company to pay down debt, which served to strengthen the Company’s balance sheet. This also enables the Company to focus on fewer, more material plays while providing for a more capital efficient business with reduced sustaining capital requirements.

Management’s Discussion and Analysis 2016

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8.5 Contractual Obligations, Commitments and Off-Balance Sheet Arrangements

Contractual Obligations and Other Commercial Commitments

In the normal course of business, the Company is obligated to make future payments. The following summarizes known non-cancellable contracts and other commercial commitments:

Contractual Obligations

Payments due by period ($ millions)	2017		2018-2019		2020-2021		Thereafter		Total
Long-term debt and interest on fixed rate debt		674		1,891		668		3,720		6,953
Operating leases(1)		252		306		229		1,650		2,437
Firm transportation agreements(1)		458		908		943		4,822		7,131
Unconditional purchase obligations(2)		2,749		2,680		2,161		1,549		9,139
Lease rentals and exploration work agreements		49		142		102		850		1,143
Obligations to fund equity investee(3)		52		110		110		379		651
Finance lease obligations(4)		35		70		70		764		939
Asset retirement obligations(5)		218		376		337		10,503		11,434
		4,487		6,483		4,620		24,237		39,827

⁽¹⁾  Included in operating leases and firm transportation agreements are blending and storage agreements and transportation commitments of $0.6 billion and $2.1 billion respectively with HMLP.

⁽²⁾  Includes purchase of refined petroleum products, processing services, distribution services, insurance premiums, drilling services and natural gas purchases.

⁽³⁾  Equity investee refers to the Company’s investment in Husky-CNOOC Madura Limited and HMLP which is accounted for using the equity method.

⁽⁴⁾  Refer to Note 17 in the 2016 Consolidated Financial Statements.

⁽⁵⁾  Asset retirement obligation amounts represent the undiscounted future payments for the estimated cost of abandonment, removal and remediation associated with retiring the Company’s assets. The amounts are inclusive of $156 million of cash deposited into restricted accounts for funding of future asset retirement obligations in the Asia Pacific Region.

The Company renewed certain purchase, distribution and terminal commitments related to light oil and asphalt products in 2016. Certain transportation, storage and operating lease commitments were signed with HMLP in conjunction with the divestiture of certain midstream assets.

Due to the harsh environment, the Henry Goodrich rig arrived in mid-2016 for development drilling at White Rose.

Husky-CNOOC Madura Limited, of which the Company is a joint venturer, has entered into an arrangement to lease an FPSO vessel for the purposes of developing the Madura BD field gas reserves. The Company is obligated to pay 40 percent of the lease payment which is included in obligations to fund equity investee. The FPSO was delivered and testing began in December 2016.

The Company updated its estimates for Asset Retirement Obligations (“ARO”) as outlined in Note 16 to the 2016 Consolidated Financial Statements. On an undiscounted and inflated basis, the ARO decreased from $13.9 billion as at December 31, 2015 to $11.4 billion as at December 31, 2016, primarily due to dispositions in Western Canada.

Other Obligations

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters, or any amount which it may be required to pay, would have a material adverse impact on its financial position, results of operations or liquidity.

The Company has income tax filings that are subject to audit and potential reassessment. The findings may impact the tax liability of the Company. The final results are not reasonably determinable at this time. Management believes that it has adequately provided for current and deferred income taxes.

The Company provides a defined contribution pension plan and a post-retirement health and dental plan for all qualified employees in Canada. The Company also provides a defined benefit pension plan for approximately 53 active employees, 74 participants with deferred benefits and 546 participants or joint survivors receiving benefits in Canada. This plan was closed to new entrants in 1991 after the majority of employees transferred to the defined contribution pension plan (Refer to Note 22 in the 2016 Consolidated Financial Statements).

The Company has an obligation to fund capital expenditures of the BP-Husky Toledo Refinery. The remaining net contribution payable amount of approximately U.S. $110 million (CDN $146 million) will be paid by way of funding all capital contributions of the BP-Husky Refining LLC joint operation and the remaining balance will be fully repaid by the end of 2017.

Management’s Discussion and Analysis 2016

43

In accordance with the provisions of the regulations of the People’s Republic of China, the Company is required to deposit funds in separate accounts restricted to future decommissioning and disposal obligations. The funds will be used for decommissioning and disposal expenses upon the expiry or termination of the contract for the Asia Pacific Region. 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 is also subject to various contingent obligations that become payable only if certain events or rulings occur. The inherent uncertainty surrounding the timing and financial impact of these events or rulings prevents any meaningful measurement, which is necessary to assess their impact on future liquidity. Such obligations include environmental contingencies, contingent consideration and potential settlements resulting from litigation.

The Company has a number of contingent environmental liabilities, which individually have been estimated to be immaterial. These contingent environmental liabilities are primarily related to the migration of contamination at fuel outlets and certain legacy sites where the Company had previously conducted operations. The contingent environmental liabilities involved have been considered in aggregate and based on reasonable estimates the Company does not believe they will result, in aggregate, in a material adverse effect on its financial position, results of operations or liquidity.

Off-Balance Sheet Arrangements

The Company does not believe it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on the Company’s financial condition, results of operations, liquidity or capital expenditures.

Standby Letters of Credit

On occasion, the Company issues letters of credit in connection with transactions in which the counterparty requires such security.

8.6 Transactions with Related Parties

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 HMLP, of which the Company owns 35 percent, PAH owns 48.75 percent and CKI owns 16.25 percent. This transaction is a related party transaction, as PAH and CKI are affiliates of one of the Company’s principal shareholders, and has been measured at fair value. 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. Subsequent to the sale of its ownership interest, the Company performs management services as the operator of the pipeline for which it earns a management fee from HMLP. The Company is also the contractor for HMLP and constructs its assets on a cost recovery basis with certain restrictions. HMLP charges an access fee to the Company for the use of its pipeline systems in performing its blending business and the Company also pays for transportation and storage services. For the year ended December 31, 2016, the Company charged HMLP $133 million related to construction and management services, and the Company had purchases from HMLP of $15 million related to the use of the pipeline for the Company’s blending activities and $64 million related to transportation and storage. As at December 31, 2016, the Company had $26 million due from HMLP and nil due to HMLP related to these transactions. All transactions with HMLP have been measured at fair value.

The Company sells natural gas to and purchases steam from the Meridian Limited Partnership (“Meridian”), owner of the Meridian cogeneration facility, for use at the facility, Upgrader and Lloydminster ethanol plant. In addition, the Company provides facilities services and personnel for the operations of the Meridian cogeneration facility, which are primarily measured and reimbursed at cost. These transactions are related party transactions, as Meridian is an affiliate of one of the Company’s principal shareholders, and have been measured at fair value. For the year ended December 31, 2016, the amount of natural gas sales to Meridian totalled $41 million. For the year ended December 31, 2016, the amount of steam purchased by the Company from Meridian totalled $13 million. For the year ended December 31, 2016, the total cost recovery by the Company for facilities services was $12 million. At December 31, 2016, the Company had under $1 million due from Meridian with respect to these transactions.

At December 31, 2016, $34 million of the May 11, 2009 7.25 percent senior notes were held by a related party, Ace Dimension Limited, and are included in long-term debt in the Company’s consolidated balance sheet. The related party transaction was measured at fair market value at the date of the transaction and has been carried out on the same terms as applied with unrelated parties.

On June 29, 2011, the Company issued 7.4 million common shares at a price of $27.05 per share for total gross proceeds of $200 million in a private placement to its then principal shareholders, L.F. Management and Investment S.à r.l (formerly L.F. Investments (Barbados) Limited) and Hutchison Whampoa Luxembourg Holdings S.à r.l, which was completed in conjunction with a public offering by the Company of common shares.

Management’s Discussion and Analysis 2016

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On December 7, 2010, the Company issued 28.9 million common shares at a price of $24.50 per share for total gross proceeds of $707 million in a private placement to its principal shareholders, L.F. Management and Investment S.à r.l (formerly L.F. Investments (Barbados) Limited) and Hutchison Whampoa Luxembourg Holdings S.à r.l, which was completed in conjunction with a public offering by the Company of common shares in Canada.

8.7 Outstanding Share Data

Authorized:

•      unlimited number of common shares

•      unlimited number of preferred shares

Issued and outstanding: February 20, 2017

•      common shares	1,005,451,845
•      cumulative redeemable preferred shares, series  1	10,435,932
•      cumulative redeemable preferred shares, series  2	1,564,068
•      cumulative redeemable preferred shares, series  3	10,000,000
•      cumulative redeemable preferred shares, series  5	8,000,000
•      cumulative redeemable preferred shares, series 7	6,000,000
•      stock options	25,300,870
•      stock options exercisable	15,596,918

Management’s Discussion and Analysis 2016

45

9.0 Critical Accounting Estimates and Key Judgments

The Company’s consolidated financial statements have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (“IASB”). Significant accounting policies are disclosed in Note 3 to the 2016 Consolidated Financial Statements. Certain of the Company’s accounting policies require subjective judgment and estimation about uncertain circumstances.

9.1 Accounting Estimates

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and on a prospective basis. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the consolidated financial statements. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Specifically, amounts recorded for depletion, depreciation, amortization and impairment, asset retirement obligations, assets and liabilities measured at fair value, employee future benefits, income taxes and estimates and reserves and contingencies are based on estimates.

Depletion, Depreciation, Amortization and Impairment

Eligible costs associated with oil and gas activities are capitalized on a unit of measure basis. Depletion expense is subject to estimates including petroleum and natural gas reserves, future petroleum and natural gas prices, estimated future remediation costs, future interest rates as well as other fair value assumptions. The aggregate of capitalized costs, net of accumulated DD&A, less estimated salvage values, is charged to DD&A over the life of the proved developed reserves using the unit of production method, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed reserves of that field, in which case the straight-line method or a unit-of-production method based on total proved plus probable reserves is applied.

Impairment and Reversals of Impairment of Non-Financial Assets

The carrying amounts of the Company’s non-financial assets are reviewed at the end of each reporting period to determine whether there is any indication of impairment. Determining whether there are any indications of impairment requires significant judgment of external factors, such as an extended decrease in prices or margins for oil and gas commodities or products, a significant decline in an asset’s market value, a significant downward revision of estimated volumes, an upward revision of future development costs, a decline in the entity’s market capitalization or significant changes in the technological, market, economic or legal environment that would have an adverse impact on the entity. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to net earnings.

The determination of the recoverable amount for impairment purposes involves the use of numerous assumptions and estimates. Estimates of future cash flows used in the evaluation of impairment of assets are made using management’s forecasts of commodity prices, operating costs and future capital expenditures, marketing supply and demand, forecasted crack spreads, growth rate, discount rate and, in the case of oil and gas properties, expected production volumes. Expected production volumes take into account assessments of field reservoir performance and include expectations about proved and probable volumes and where applicable economically recoverable resources associated with interests in certain Husky properties which are risk-weighted utilizing geological, production, recovery, market price and economic projections. Either the cash flow estimates or the discount rate is risk-adjusted to reflect local conditions as appropriate. Future revisions to these assumptions impact the recoverable amount.

Impairment losses recognized for other assets in prior years are assessed at the end of each reporting period for indications that the impairment has decreased or no longer exists. An impairment loss is reversed only to the extent that the carrying amount of the asset or cash generating units (“CGUs”) does not exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had been recognized.

Asset Retirement Obligations

Estimating ARO requires that the Company estimates costs that are many years in the future. Restoration technologies and costs are constantly changing, as are regulatory, political, environment, safety and public relations considerations. Inherent in the calculation of ARO are numerous assumptions and estimates, including the ultimate settlement amounts, future third-party pricing, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Future revisions to these assumptions may result in changes to the ARO.

Fair Value of Financial Instruments

The fair values of derivatives are determined using valuation models which require assumptions concerning the amount and timing of future cash flows and discount rates. These estimates are also subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance. The actual settlement of a derivative instrument could differ materially from the fair value recorded and could impact future results.

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46

Employee Future Benefits

The determination of the cost of the defined benefit pension plan and the other post-retirement benefit plans reflects a number of estimates that affect expected future benefit payments. These estimates include, but are not limited to, attrition, mortality, the rate of return on pension plan assets, salary escalations for the defined benefit pension plan and expected health care cost trends for the post-retirement health and dental care plan. The fair value of the plan assets is used for the purposes of calculating the expected return on plan assets.

Income Taxes

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. Estimates that require significant judgments are also made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where the transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment, often after the passage of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

Legal, Environmental Remediation and Other Contingent Matters

The Company is required to determine both whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can be reasonably estimated. When a loss is determined it is charged to net earnings. The Company must continually monitor known and potential contingent matters and make appropriate provisions by charges to net earnings when warranted by circumstances.

9.2 Key Judgments

Management makes judgments regarding the application of IFRS for each accounting policy. Critical judgments that have the most significant effect on the amounts recognized in the consolidated financial statements include determination of technical feasibility and commercial viability, impairment assessments, the determination of CGUs, changes in reserve estimates, the determination of a joint arrangement, the designation of the Company’s functional currency and the fair value of related party transactions.

Exploration and Evaluation Costs

Costs directly associated with an exploration well are initially capitalized as exploration and evaluation assets. Expenditures related to wells that do not find reserves or where no future activity is planned are expensed as exploration and evaluation expenses. Exploration and evaluation costs are excluded from costs subject to depletion until technical feasibility and commercial viability is assessed or production commences. At that time, costs are either transferred to property, plant and equipment or their value is impaired. Impairment is charged directly to net earnings. Drilling results, required operating costs and capital expenditure and estimated reserves are important judgments when making this determination and may change as new information becomes available.

Impairment of Financial Assets

A financial asset is assessed at the end of each reporting period to determine whether it is impaired based on objective evidence indicating that one or more events have had a negative effect on the estimated future cash flows of that asset. Objective evidence used by the Company to assess impairment of financial assets includes quoted market prices for similar financial assets and historical collection rates for loans and receivables. The calculations for the net present value of estimated future cash flows related to derivative financial assets requires the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and expected production volumes, and it is possible that the assumptions may change, which may require a material adjustment to the carrying value of financial assets.

Cash Generating Units

The Company’s assets are grouped into respective CGUs, which is the smallest identifiable group of assets, liabilities and associated goodwill that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. The determination of the Company’s CGUs is subject to management’s judgment.

Reserves

Oil and gas reserves are evaluated internally and audited by independent qualified reserve engineers. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Estimates are based on projected future rates of production, estimated commodity prices, engineering data and the timing of future expenditures, all of which are subject to uncertainty. Changes in reserve estimates can have an impact on reported net earnings through revisions to depletion, depreciation and amortization expense, in addition to determining possible impairments and reversal of impairments of property, plant and equipment.

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Net reserves represent the Company’s undivided gross working interest in total reserves after deducting crown, freehold and overriding royalty interests. Assumptions reflect market and regulatory conditions, as applicable, as at the balance sheet date and could differ significantly from other points in time throughout the year or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Joint Arrangements

Joint arrangements represent activities where the Company has joint control established by a contractual agreement. Joint control requires unanimous consent for financial and operational decisions. A joint arrangement is either a joint operation, whereby the parties have rights to the assets and obligations for the liabilities, or a joint venture, whereby the parties have rights to the net assets.

Classification of a joint arrangement as either joint operation or joint venture requires judgment. Management’s considerations include, but are not limited to, determining if the arrangement is structured through a separate vehicle and whether the legal form and contractual arrangements give the entity direct rights to the assets and obligations for the liabilities within the normal course of business. Other facts and circumstances are also assessed by management, including the entity’s rights to the economic benefits of assets and its involvement and responsibility for settling liabilities associated with the arrangement.

Functional and Presentation Currency

Functional currency is the currency of the primary economic environment in which the Company and its subsidiaries operate and is normally the currency in which the entity primarily generates and expends cash. The designation of the Company’s functional currency is a management judgment based on the composition of revenues and costs in the locations in which it operates.

Related Party Judgments and Estimates

The Company entered into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. These transactions are on terms equivalent to those that prevail in arm’s length transactions, unless otherwise noted. Proceeds for disposition of assets to related parties are recognized at fair value, based on discounted cash flow forecast from those assets. Independent opinions of the fair value may be obtained. Changes in the assumptions used to determine these fair values may result in a material difference in the proceeds and any gain or loss on disposition.

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10.0 Recent Accounting Standards and Changes in Accounting Policies

Recent Accounting Standards

The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

Leases

In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under the current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the balance sheet, while operating leases are recognized in the Consolidated Statements of Income (Loss) when the expense is incurred. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. The recognition of the present value of minimum lease payments for certain contracts currently classified as operating leases will result in increases to assets, liabilities, depletion, depreciation and amortization, and finance expense, and a decrease to production, operating and transportation expense upon implementation. An optional exemption to not recognize certain short-term leases and leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged. The standard will be effective for annual periods beginning on or after January 1, 2019. Early adoption is permitted, provided IFRS 15 Revenue from Contracts with Customers, has been applied, or is applied at the same date as IFRS 16. The Company is currently evaluating the dollar impact of adopting IFRS 16 on the Company’s consolidated financial statements.

Revenue from Contracts with Customers

In September 2015, the IASB published an amendment to IFRS 15, deferring the effective date of the standard by one year to annual periods beginning on or after January 1, 2018. IFRS 15 replaces existing revenue recognition guidance with a single comprehensive accounting model. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Early adoption is permitted. The Company is currently in the scoping phase of implementation. Adopting IFRS 15 is not expected to have a material impact on the Company’s consolidated financial statements.

Financial Instruments

In July 2014, the IASB issued IFRS 9, “Financial Instruments” to replace IAS 39, which provides a single model for classification and measurement based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial instruments. For financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. IFRS 9 includes a new, forward-looking ‘expected loss’ impairment model that will result in more timely recognition of expected credit losses. In addition, IFRS 9 provides a substantially-reformed approach to hedge accounting. The standard is effective for annual periods beginning on or after January 1, 2018, with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt the standard on January 1, 2018. The adoption of IFRS 9 is not expected to have a material impact on the Company’s consolidated financial statements.

Amendments to IAS 7 Statement of Cash Flows

In January 2016, the IASB issued amendments to IAS 7 to be applied prospectively for annual periods beginning on or after January

1, 2017 with early adoption permitted. The amendments require disclosure of information enabling users of financial statements to evaluate changes in liabilities arising from financing activities. The adoption of the IAS 7 amendments will require additional disclosure in the Company’s consolidated financial statements.

Amendments to IFRS 2 Share-based Payment

In June 2016, the IASB issued amendments to IFRS 2 to be applied prospectively for annual periods beginning on or after January 1, 2018 with early adoption permitted. The amendments clarify how to account for certain types of share-based payment transactions. The adoption of the amendments is not expected to have a material impact on the Company’s consolidated financial statements.

Change in Accounting Policy

The Company has applied the following amendments to accounting standards issued by the IASB for the first time for the annual reporting period commencing January 1, 2016:

Amendments to IAS 1 Presentation of Financial Statements

The amendments clarify guidance on materiality and aggregation, use of subtotals, aggregation and disaggregation of financial statement line items, the order of the notes to the financial statements and disclosure of significant accounting policies. The adoption of this amended standard had no material impact on the Company’s consolidated financial statements.

Amendments to IFRS 7 Financial Instrument: Disclosures

The amendments clarify:

• Whether a servicing contract is continuing involvement in a transferred asset for the purpose of determining the disclosures required; and

• The applicability of the amendments to IFRS 7 on offsetting disclosures to condensed interim financial statements.

The adoption of this amended standard had no material impact on the Company’s consolidated financial statements.

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11.0 Reader Advisories

11.1 Forward-Looking Statements

Special Note Regarding Forward-Looking Statements

Certain statements in this document are forward-looking statements and information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this document are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “estimated”, “intend”, “plan”, “projection”, “forecast”, “guidance”, “could”, “may”, “would”, “aim”, “vision”, “goals”, “objective”, “target”, “schedules” and “outlook”). In particular, forward-looking statements in this document include, but are not limited to, references to:

• with respect to the business, operations and results of the Company generally: the Company’s general strategic plans and growth strategies; the Company’s 2017 production guidance, including guidance for specified areas and product types; the Company’s 2017 Upstream capital expenditures program, including guidance for specified areas and product types; and the Company’s objective to maintain debt to capital employed and debt to funds from operations below certain levels;

• with respect to the Company’s Asia Pacific Region: anticipated volumes of peak combined net sales volumes of gas and NGL from the BD, MDA, MBH and MDK fields; anticipated timing of signing the floating production vessel lease contract for, and first production at, the MDA, MBH, and MDK gas fields; anticipated timing of exploration and drilling plans at Block 15/33; anticipated timing of acquisition of seismic surveying data at the Taiwan exploration block; and anticipated timing of first production from and achieving full gas sales rates at the BD field;

• with respect to the Company’s Atlantic Region: anticipated exploration and growth potential in the region; and timing to consider sanction of the West White Rose extension project;

• with respect to the Company’s Oil Sands properties: anticipated range of daily production volumes from the Company’s Sunrise Energy Project for 2017; and expected improved well conformance and production rates at the Company’s Sunrise Energy Project over the next two years;

• with respect to the Company’s Heavy Oil properties: the Company’s strategic plans for its Heavy Oil Thermal production; anticipated timing of first production from, and combined nameplate capacities of, the Dee Valley, Spruce Lake North and Spruce Lake Central thermal projects; nameplate capacity for the Company’s Edam West thermal development; and nameplate capacity and expected timing for first production of the Rush Lake 2 thermal development;

• with respect to the Company’s Western Canadian oil and gas resource plays: the Company’s strategic plans for its Western Canada resource plays;

• with respect to the Company’s Infrastructure and Marketing business: the Company’s plans to expand export pipeline access and product storage opportunities to enhance market access; and

• with respect to the Company’s Downstream operating segment: potential expansion of the Company’s asphalt processing capacity in Lloydminster and the benefits and timing of such expansion; anticipated timing of completion, outcome, and benefits of the crude oil flexibility project at the Company’s Lima Refinery; and the timing of the implementation of the agreement with Imperial Oil and consolidation of the two networks to create a single expended truck transport network.

In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve and production estimates.

Although the Company believes that the expectations reflected by the forward-looking statements presented in this document are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources including third party consultants, suppliers, regulators and other sources.

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Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Husky.

The Company’s Annual Information Form for the year ended December 31, 2016 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.

11.2 Oil and Gas Reserves Reporting

Disclosure of Oil and Gas Reserves and Other Oil and Gas Information

Unless otherwise stated, reserve estimates in this document, have been prepared by internal qualified reserves evaluators in accordance with the Canadian Oil and Gas Evaluation Handbook, have an effective date of December 31, 2016 and represent Husky’s share. Unless otherwise noted, historical production numbers given represent Husky’s share.

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 but does not represent value equivalency at the wellhead.

The Company uses the term reserve replacement ratio, which is consistent with other oil and gas companies’ disclosures. Reserve replacement ratios for a given period are determined by taking the Company’s incremental proved reserve additions for that period divided by the Company’s upstream gross production for the same period. The reserve replacement ratio measures the amount of reserves added to a company’s reserve base during a given period relative to the amount of oil and gas produced during that same period. A company’s reserve replacement ratio must be at least 100 percent for the company to maintain its reserves. The reserve replacement ratio only measures the amount of reserves added to a company’s reserve base during a given period.

Steam-oil ratio measures the average volume of steam required to produce a barrel of oil. This measure does not have any standardized meaning and should not be used to make comparisons to similar measures presented by other issuers.

Note to U.S. Readers

The Company reports its reserves information in accordance with Canadian practices and specifically in accordance with National Instrument 51-101, “Standards of Disclosure for Oil and Gas Disclosure”, adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves information in accordance with Canadian disclosure requirements, it may use certain terms in that disclosure that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the Securities and Exchange Commission.

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11.3 Non-GAAP Measures

Disclosure of non-GAAP Measurements

The Company uses measurements primarily based on IFRS and also on secondary non-GAAP measurements. The non-GAAP measurements included in this MD&A and related disclosures are: adjusted net earnings (loss), funds from operations, free cash flow, net debt, operating netback, debt to capital employed, earnings coverage, debt to funds from operations and LIFO. None of these measurements are used to enhance the Company’s reported financial performance or position. There are no comparable measures in accordance with IFRS for operating netback, debt to capital employed, earnings coverage or debt to funds from operations. These are useful complementary measures in assessing the Company’s financial performance, efficiency and liquidity. The non-GAAP measurements do not have a standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application. All non-GAAP measures are defined below.

Adjusted Net Earnings (Loss)

The term “adjusted net earnings (loss)” is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “net earnings (loss)” as determined in accordance with IFRS, as an indicator of financial performance. Adjusted net earnings (loss) is comprised of net earnings (loss) and excludes items such as after-tax property, plant and equipment impairment charges (reversals), goodwill impairment charges, exploration and evaluation asset write-downs, inventory write-downs and loss (gain) on sale of assets which are not considered to be indicative of the Company’s ongoing financial performance. Adjusted net earnings (loss) is a complementary measure used in assessing the Company’s financial performance through providing comparability between periods. Adjusted net earnings (loss) was redefined in the second quarter of 2016. Previously, adjusted net earnings (loss) was defined as net earnings (loss) plus after-tax property, plant and equipment impairment charges (reversals), goodwill impairment charges, exploration and evaluation asset write-downs and inventory write-downs.

The following table shows the reconciliation of net earnings (loss) to adjusted net earnings (loss) for the three months and years ended December 31:

	Three months ended Dec. 31,						Year ended Dec. 31,
($ millions)	2016			2015			2016			2015			2014
Net earnings (loss)		186			(69	)		922			(3,850	)		1,258
Impairment (impairment reversal) of property, plant and equipment, net of tax		(202	)		—			(190	)		3,664			622
Impairment of goodwill		—			—			—			160			—
Exploration and evaluation asset write-downs, net of tax		41			6			63			177			4
Inventory write-downs, net of tax		6			14			6			14			135
Loss (gain) on sale of assets, net of tax		(37	)		(4	)		(1,456	)		(16	)		(27	)
Adjusted net earnings (loss)		(6	)		(53	)		(655	)		149			1,992

Funds from Operations and Free Cash Flow

The term “funds from operations” is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “cash flow – operating activities” as determined in accordance with IFRS, as an indicator of financial performance. Funds from operations is presented in the Company’s financial reports to assist management and investors in analyzing operating performance of the Company in the stated period. Funds from operations equals cash flow - operating activities less the settlement of asset retirement obligations, deferred revenue, income taxes received (paid) and change in non-cash working capital.

The term “free cash flow” is a non-GAAP measure, which should not be considered an alternative to, or more meaningful than, “cash flow - operating activities” as determined in accordance with IFRS, as an indicator of financial performance. Free cash flow is presented to assist management and investors in analyzing operating performance by the business in the stated period. Free cash flow equals funds from operations less capital expenditures.

Management’s Discussion and Analysis 2016

52

The following table shows the reconciliation of cash flow – operating activities to funds from operations and free cash flow, and related per share amounts for the three months and years ended December 31:

	Three months ended Dec. 31,						Year ended Dec. 31,
($ millions)	2016			2015			2016			2015			2014
Cash flow – operating activities		644			1,291			1,971			3,760			5,585
Settlement of asset retirement obligations		31			31			87			98			167
Deferred revenue		(23	)		(26	)		(209	)		(102	)		—
Income taxes received (paid)		6			31			(3	)		227			661
Interest received		(1	)		(3	)		(5	)		(3	)		(7	)
Change in non-cash working capital		13			(684	)		235			(651	)		(871	)
Funds from operations		670			640			2,076			3,329			5,535
Capital expenditures		(391	)		(641	)		(1,705	)		(3,005	)		(5,023	)
Free cash flow		279			(1	)		371			324			512
Funds from operations – basic		0.67			0.65			2.07			3.38			5.63
Funds from operations – diluted		0.67			0.65			2.07			3.38			5.62

Net Debt

Net debt is a non-GAAP measure that equals total debt less cash and cash equivalents. Total debt is calculated as long-term debt, long-term debt due within one year and short-term debt. Management believes this measurement assists management and investors in evaluating the Company’s financial strength.

The following table shows the reconciliation of total debt to net debt as at December 31, 2016, 2015 and 2014:

($ millions)	December 31, 2016			December 31, 2015			December 31, 2014
Short-term debt		200			720			895
Long-term debt due within one year		403			277			300
Long-term debt		4,736			5,759			4,097
Total Debt		5,339			6,756			5,292
Cash and cash equivalents		(1,319	)		(70	)		(1,267	)
Net Debt		4,020			6,686			4,025

Operating Netback

Operating netback is a common non-GAAP metric used in the oil and gas industry. Management believes this measurement assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. The operating netback was determined as gross revenue less royalties, production and operating and transportation costs on a per unit basis.

Debt to Capital Employed

Debt to capital employed percentage is a non-GAAP measure and is equal to long-term debt, long-term debt due within one year, and short-term debt divided by capital employed. Capital employed is equal to long-term debt, long-term debt due within one year, short-term debt and shareholders’ equity. Management believes this measurement assists management and investors in evaluating the Company’s financial strength.

Debt to Funds from Operations

Debt to funds from operations is a non-GAAP measure and is equal to long-term debt, long-term debt due within one year and short-term debt divided by funds from operations. Funds from operations is equal to cash flow - operating activities less the settlement of asset retirement obligations, deferred revenue, income taxes received (paid) and change in non-cash working capital. Management believes this measurement assists management and investors in evaluating the Company’s financial strength.

The following table shows the reconciliation of debt to funds from operations for the periods ended December 31, 2016, 2015 and 2014:

($ millions)	December 31, 2016		December 31, 2015		December 31, 2014
Total Debt		5,339		6,756		5,292
Funds from operations		2,076		3,329		5,535
Debt to Funds from Operations		2.6		2.0		1.0

Management’s Discussion and Analysis 2016

53

Earnings Coverage

Earnings coverage is a non-GAAP measure and is equal to net earnings (loss) before finance expense on long-term debt, capitalized interest and income taxes divided by finance expense on long-term debt, dividends on preferred shares and capitalized interest. Long-term debt includes the current portion of long-term debt. The Company’s earnings coverage on long-term debt was 3.2 times for the twelve month period ended December 31, 2016.

LIFO

The Chicago 3:2:1 market crack spread benchmark is based on LIFO inventory costing, a non-GAAP measure, which assumes that crude oil feedstock costs are based on the current month price of WTI, while on a FIFO basis, the comparable GAAP measure, crude oil feedstock costs included in realized margins reflect purchases made in previous months. Management believes that comparisons between LIFO and FIFO inventory costing assist management and investors in assessing differences in the Company’s realized refining margins compared to the Chicago 3:2:1 market crack spread benchmark.

11.4 Additional Reader Advisories

Intention of Management’s Discussion and Analysis

This Management’s Discussion and Analysis is intended to provide an explanation of financial and operational performance compared with prior periods and the Company’s prospects and plans. It provides additional information that is not contained in the Company’s Consolidated Financial Statements.

Review by the Audit Committee

This Management’s Discussion and Analysis was reviewed by the Audit Committee and approved by the Company’s Board of Directors on February 23, 2017. Any events subsequent to that date could materially alter the veracity and usefulness of the information contained in this document.

Additional Husky Documents Filed with Securities Commissions

This Management’s Discussion and Analysis dated February 23, 2017 should be read in conjunction with the 2016 Consolidated Financial Statements and related notes. The readers are also encouraged to refer to the Company’s interim reports filed for 2016, which contain the Management’s Discussion and Analysis and Consolidated Financial Statements, and the Company’s 2016 Annual Information Form filed separately with Canadian regulatory agencies and Form 40-F filed with the SEC, the U.S. regulatory agency. These documents are available at www.sedar.com, at www.sec.gov and www.huskyenergy.com. Husky’s Management’s Discussion and Analysis for the interim period ended December 31, 2016 is incorporated herein by reference.

Use of Pronouns and Other Terms

“Husky” and “the Company” refer to Husky Energy Inc. on a consolidated basis.

Standard Comparisons in this Document

Unless otherwise indicated, comparisons of results are for the years ended December 31, 2016 and 2015 and the Company’s financial position at December 31, 2016 and 2015. All currency is expressed in Canadian dollars unless otherwise directed.

Reclassifications and Materiality for Disclosures

Certain prior year amounts have been reclassified to conform to current year presentation. Materiality for disclosures is determined on the basis of whether the information omitted or misstated would cause a reasonable investor to change their decision to buy, sell or hold Husky’s securities.

Additional Reader Guidance

Unless otherwise indicated:

• Financial information is presented in accordance with IFRS as issued by the IASB;

• Currency is presented in millions of Canadian dollars (“$ millions”);

• Gross production and reserves are the Company’s working interest prior to deduction of royalty volume; and

• Prices are presented before the effect of hedging.

Management’s Discussion and Analysis 2016

54

Terms

Adjusted Net Earnings (Loss)	Net earnings (loss) before after-tax property, plant and equipment impairment charges (reversals), goodwill impairment charges, exploration and evaluation asset write-downs, inventory write-downs and loss (gain) on the sale of assets
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
Capital Employed	Long-term debt, long-term debt due within one year, short-term debt and shareholders’ equity
Capital Expenditures	Includes capitalized administrative expenses but does not include asset retirement obligations or capitalized interest
Capital Program	Capital expenditures not including capitalized administrative expenses or capitalized interest
Debt to Capital Employed	Long-term debt, long-term debt due within one year and short-term debt divided by capital employed
Debt to Funds from Operations	Long-term debt, long-term debt due within one year and short-term debt divided by funds from operations
Diluent	A lighter gravity liquid hydrocarbon, usually condensate or synthetic oil, added to heavy oil and bitumen to facilitate transmissibility of the oil through a pipeline
Earnings Coverage	Net earnings (loss) before finance expense on long-term debt, capitalized interest and income taxes divided by finance expense on long-term debt, dividends on preferred shares and capitalized interest. Long-term debt includes the current portion of long-term debt
Feedstock	Raw materials which are processed into petroleum products
Free Cash Flow	Funds from operations less capital expenditures
Funds from Operations	Cash flow - operating activities plus items affecting cash which includes settlement of asset retirement obligations, deferred revenue, income taxes received (paid) and change in non-cash working capital.
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
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 1 are referred to as Hi-TAN crudes
Last in first out (“LIFO”)	Last in first out accounting assumes that crude oil feedstock costs are based on the current month price of WTI
Light crude oil	Crude oil with a relative density greater than 31.1 degrees API gravity
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
Net Debt	Total debt less cash and cash equivalents
Net Revenue	Gross revenues less royalties
NOVA Inventory Transfer (“NIT”)	Exchange or transfer of title of gas that has been received into the NOVA pipeline system but not yet delivered to a connecting pipeline
Oil sands	Sands and other rock materials that contain crude bitumen and include all other mineral substances in association therewith
Operating Netback	Gross revenue less royalties, operating costs and transportation costs on a per unit basis
Proved reserves	Reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Proved developed reserves	Those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing
Proved undeveloped reserves	Those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned
Probable reserves	Those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves

Management’s Discussion and Analysis 2016

55

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
Shareholders’ Equity	Common shares, preferred shares, retained earnings and other reserves
Steam-oil ratio	The steam-oil ratio measures the volume of steam used to produce one unit volume of oil
Stratigraphic Well	A geologically directed test well to obtain information. These wells are usually drilled without the intention of being completed for production
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
Total Debt	Long-term debt including long-term debt due within one year and short-term debt
Turnaround	Performance of plant or facility maintenance

Abbreviations

ARO	asset retirement obligations	mbbls/day	thousand barrels per day
bbls	barrels	mboe	thousand barrels of oil equivalent
bbls/day	barrels per day	mboe/day	thousand barrels of oil equivalent per day
bcf	billion cubic feet	mcf	thousand cubic feet
boe	barrels of oil equivalent	mcfge	thousand cubic feet of gas equivalent
boe/day	barrels of oil equivalent per day	MD&A	Management’s Discussion and Analysis
bps	basis points	mmbbls	million barrels
CGUs	cash generating units	mmboe	million barrels of oil equivalent
CHOPS	cold heavy oil production with sand	mmbtu	million British Thermal Units
CO2e	carbon dioxide equivalent	mmcf	million cubic feet
CSA	Canadian Securities Administrators	mmcf/day	million cubic feet per day
DD&A	depletion, depreciation and amortization	m3	cubic meter
ELs	exploration licenses	NGL	natural gas liquids
EOR	enhanced oil recovery	NIT	NOVA Inventory Transfer
EPA	U.S. Environmental Protection Agency	NYMEX	New York Mercantile Exchange
FEED	front end engineering and design	OPEC	Organization of Petroleum Exporting Countries
FIFO	first in first out	PHMSA	Pipeline and Hazardous Materials Safety Administration
FPSO	floating production, storage and offloading vessel	PSC	production sharing contract
FVTPL	fair value through profit or loss	RFS	Renewable Fuel Standard
GAAP	Generally Accepted Accounting Principles	RIN	Renewable Identification Number
GHG	greenhouse gas	RVO	renewable volume obligation
GJ	gigajoule	S&P	Standard and Poor’s
HOIMS	Husky Operational Integrity Management System	SAGD	steam assisted gravity drainage
IASB	International Accounting Standards Board	SEC	U.S. Securities and Exchange Commission
IFRIC	International Financial Reporting Interpretations Committee Interpretation	SEDAR	System for Electronic Document Analysis and Retrieval
IFRS	International Financial Reporting Standards	tCO2e	tons of carbon dioxide equivalent
LFEs	Large Final Emitting Facilities	TSX	Toronto Stock Exchange
LIFO	last in first out	WI	working interest
mbbls	thousand barrels	WTI	West Texas Intermediate

Management’s Discussion and Analysis 2016

56

11.5 Disclosure Controls and Procedures

Disclosure Controls and Procedures

Husky’s management, under supervision of the Chief Executive Officer and the Chief Financial Officer, have evaluated the effectiveness of Husky’s disclosure controls and procedures (as defined in the rules of the SEC and the Canadian Securities Administrators (“CSA”)) as at December 31, 2016, and have concluded that such disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control over Financial Reporting

The following report is provided by management in respect of Husky’s internal controls over financial reporting (as defined in the rules of the SEC and the CSA):

1) Husky’s management, under the supervision of the Chief Executive Officer and Chief Financial Officer, is responsible for designing, establishing and maintaining adequate internal control over financial reporting for Husky. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

2) Husky’s management has used the Committee of Sponsoring Organizations of the Treadway Commission framework to evaluate the effectiveness of Husky’s internal control over financial reporting.

3) As at December 31, 2016, management, under the supervision of the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of Husky’s internal control over financial reporting and concluded that such internal control over financial reporting is effective.

4) KPMG LLP, who has audited the Consolidated Financial Statements of Husky for the year ended December 31, 2016, has also issued a report on internal controls over financial reporting under Auditing Standard No. 5 of the Public Company Accounting Oversight Board (United States) that attests to Husky’s internal controls over financial reporting.

Changes in Internal Control over Financial Reporting

There have been no changes in Husky’s internal control over financial reporting during the year ended December 31, 2016, that have materially affected or are reasonably likely to materially affect its internal control over financial reporting.

Management’s Discussion and Analysis 2016

57

12.0 Selected Quarterly Financial and Operating Information

12.1 Summary of Quarterly Results

Gross Revenues and Marketing and Other

($ billions)

Funds From Operations⁽¹⁾

($ billions)

Net Earnings (Loss)

($ billions)

Net Earnings (Loss) Per Share

($ per share)

⁽¹⁾  Funds from operations is a non-GAAP measure. Refer to Section 11.3.

Management’s Discussion and Analysis 2016

58

	Three months ended
Fourth Quarter Results Summary ($ millions, except where indicated)	Dec. 31 2016			Dec. 31 2015
Gross revenues and marketing and other
Upstream
Exploration and Production		1,215			1,189
Infrastructure and Marketing		186			301
Downstream
Upgrader		340			364
Canadian Refined Products		603			699
U.S. Refining and Marketing		1,890			1,692
Corporate and Eliminations		(369	)		(342	)
Total gross revenues and marketing and other		3,865			3,903
Net earnings (loss)
Upstream
Exploration and Production		198			(134	)
Infrastructure and Marketing		18			10
Downstream
Upgrader		32			57
Canadian Refined Products		8			49
U.S. Refining and Marketing		19			(5	)
Corporate and Eliminations		(89	)		(46	)
Net earnings (loss)		186			(69	)
Per share – Basic		0.19			(0.08	)
Per share – Diluted		0.19			(0.09	)
Adjusted net earnings (loss)(1)		(6	)		(53	)
Funds from operations(1)		670			640
Per share – Basic		0.67			0.65
Per share – Diluted		0.67			0.65
Upstream
Daily gross production
Crude oil and NGL production (mbbls/day)		234.5			246.9
Natural gas production (mmcf/day)		555.4			660.7
Total production (mboe/day)		327.0			357.0
Average sales prices realized ($/boe)
Crude oil and NGL ($/bbl)		42.27			35.71
Natural gas ($/mcf)		5.65			5.51
Total average sales prices realized ($/boe)		39.90			34.89
Downstream
Refinery throughput
Lloydminster Upgrader (mbbls/day)		66.5			81.2
Lloydminster Refinery (mbbls/day)		28.4			28.2
Prince George Refinery (mbbls/day)		11.8			11.3
Lima Refinery (mbbls/day)		165.1			144.8
Toledo Refinery (mbbls/day)(2)		78.8			72.8
Total throughput (mbbls/day)		350.6			338.3
Upgrader unit margin ($/bbl)		18.85			20.47
Upgrader synthetic crude oil sales (mbbls/day)		50.0			59.4
Upgrader total sales (mbbls/day)		66.9			80.7
Retail fuel sales (million of litres/day)		6.6			7.3
Canadian light oil margins ($/litre)		0.057			0.048
Lloydminster Refinery asphalt margin ($/bbl)		20.80			23.57
U.S. Refining Margin (U.S. $/bbl crude throughput)		9.86			4.51
U.S./Canadian dollar exchange rate (U.S. $)		0.750			0.749

⁽¹⁾  Adjusted net earnings (loss) and funds from operations are non-GAAP measures. Refer to Section 11.3 for a reconciliation to the GAAP measures.

⁽²⁾  BP-Husky Toledo Refinery throughput was revised in the first quarter of 2016 to reflect total throughput. Prior periods reflected crude throughput only and have been restated to conform with current presentation.

Management’s Discussion and Analysis 2016

59

Gross Revenue and Marketing and other

The Company’s consolidated gross revenues and marketing and other decreased by $38 million in the fourth quarter of 2016 compared to the fourth quarter of 2015.

In the Upstream business segment, Exploration and Production gross revenues increased primarily due to higher crude and North American natural gas pricing in the fourth quarter of 2016, which was partially offset by a higher Canadian dollar and lower Liwan natural gas pricing. Infrastructure and Marketing gross revenues and marketing and other decreased primarily due to the sale of select midstream assets.

In the Downstream business segment, Upgrader gross revenues decreased primarily due to reduced sales volumes resulting from plant maintenance in the fourth quarter of 2016. Canadian Refined Products gross revenues decreased primarily due to lower refined product prices and lower fuel sales volumes and demand resulting from a weak economic environment. U.S. Refining and Marketing gross revenues increased primarily due to higher sales price and volume at both the BP-Husky Toledo Refinery and Lima Refinery.

Net Earnings (Loss)

The Company’s consolidated net earnings increased by $255 million in the fourth quarter of 2016 compared to the same period in 2015.

In the Upstream business segment, Exploration and Production net earnings increased primarily due to higher commodity prices, lower operating costs due to cost saving initiatives and a net impairment reversal in the fourth quarter of 2016. The increase to net earnings was partially offset by a higher Canadian dollar and lower Liwan natural gas pricing.

In the Downstream business segment, Upgrader net earnings decreased primarily due to lower average upgrading differentials and lower sales volumes due to plant maintenance. The decline in upgrading differentials was attributable to significantly higher heavy crude oil feedstock costs partially offset by higher realized prices for Husky Synthetic Blend. During the fourth quarter of 2016, the price of Husky Synthetic Blend averaged $64.39/bbl compared to $56.50/bbl in the fourth quarter of 2015. Canadian Refined Products net earnings decreased primarily due to a lower asphalt gross margin due to lower asphalt prices and rising crude feedstock costs in the fourth quarter of 2016. U.S. Refining and Marketing net earnings increased primarily due to the factors noted above that positively impacted gross revenue. The Company recorded FIFO gains of $25 million during the fourth quarter of 2016 compared to FIFO losses of $72 million during the fourth quarter of 2015. During the fourth quarter of 2016, the Company recorded pre-tax business interruption loss and property damage insurance recoveries associated with the unplanned outage in the isocracker unit of $1 million compared to $79 million in the fourth quarter of 2015.

Adjusted Net Earnings (Loss)

Adjusted net earnings (loss), which excludes after-tax property, plant and equipment impairment (reversal), goodwill impairment charges, exploration and evaluation asset write-downs, inventory write-downs and losses (gains) on sale of assets, increased by $47 million in the fourth quarter of 2016 compared to the fourth quarter of 2015. The increase was primarily attributable to higher adjusted net earnings from Exploration and Production due to an increase in average realized crude oil and North American natural gas prices and higher U.S. Refining and Marketing adjusted net earnings due to a higher volume and margins. The increase was partially offset by lower adjusted net earnings from the Upgrader primarily due to lower average upgrading differentials and sales volume and from Canadian Refined Products primarily due to lower asphalt prices and rising crude feedstock prices. Adjusted net earnings (loss) is a non-GAAP measure; refer to section 11.3.

Funds from Operations

Funds from operations increased by $30 million in the fourth quarter of 2016 compared to the fourth quarter of 2015 primarily due to the same factors which impacted adjusted net earnings (loss). Funds from operations is a non-GAAP measure; refer to section 11.3.

Daily Gross Production

Production decreased by 30 mbbls/day during the fourth quarter of 2016 compared to the fourth quarter of 2015 as a result of:

• Disposition of select legacy Western Canada crude oil and natural gas assets; and

• Natural reservoir declines at mature properties in Western Canada and the Atlantic Region with limited sustaining capital investment in a low commodity price environment.

Partially offset by:

• Increased thermal production driven by the Rush Lake ramp up, strong production performance from Tucker, and new production from Edam East, Vawn and Edam West; and

• The production ramp up at the Sunrise Energy Project.

Management’s Discussion and Analysis 2016

60

Segmented Operational Information

	2016												2015
Segmented Operational Information	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues and marketing and other
Upstream
Exploration and Production		1,215			941			1,044			836			1,189			1,253			1,577			1,355
Infrastructure and Marketing		186			280			288			113			301			273			293			435
Downstream
Upgrader		340			334			369			281			364			190			418			347
Canadian Refined Products		603			678			585			435			699			839			747			601
U.S. Refining and Marketing		1,890			1,642			1,337			1,126			1,692			1,973			1,955			1,725
Corporate and Eliminations		(369	)		(355	)		(362	)		(213	)		(342	)		(242	)		(464	)		(377	)
Total gross revenues and marketing and other		3,865			3,520			3,261			2,578			3,903			4,286			4,526			4,086
Net earnings (loss)
Upstream
Exploration and Production		198			63			(228	)		(250	)		(134	)		(4,103	)		18			(119	)
Infrastructure and Marketing		18			1,306			35			(51	)		10			32			(21	)		63
Downstream
Upgrader		32			27			58			58			57			(29	)		28			37
Canadian Refined Products		8			55			36			11			49			69			39			13
U.S. Refining and Marketing		19			(16	)		61			(7	)		(5	)		36			172			194
Corporate and Eliminations		(89	)		(45	)		(158	)		(219	)		(46	)		(97	)		(116	)		3
Net earnings (loss)		186			1,390			(196	)		(458	)		(69	)		(4,092	)		120			191
Per share – Basic		0.19			1.37			(0.20	)		(0.47	)		(0.08	)		(4.17	)		0.11			0.19
Per share – Diluted		0.19			1.37			(0.20	)		(0.47	)		(0.09	)		(4.19	)		0.10			0.17
Adjusted net earnings (loss)(1)		(6	)		(100	)		(91	)		(458	)		(53	)		(101	)		124			191
Funds from operations(1)		670			484			488			434			640			674			1,177			838
Per share – Basic		0.67			0.48			0.49			0.43			0.65			0.68			1.20			0.85
Per share – Diluted		0.67			0.48			0.49			0.43			0.65			0.68			1.20			0.85
U.S./Canadian dollar exchange rate (U.S. $)		0.750			0.766			0.776			0.728			0.749			0.764			0.813			0.806
Exploration and Production
Daily production, before royalties
Crude oil & NGL production (mbbls/day)
Light & Medium crude oil		54.9			47.6			69.4			80.9			84.3			72.1			77.3			88.5
NGL		15.9			13.4			12.8			14.0			16.9			16.7			19.0			20.4
Heavy crude oil		48.4			49.5			57.5			61.5			66.7			67.9			70.0			71.9
Bitumen		115.3			103.6			88.0			81.8			79.0			66.7			50.3			55.7
Total crude oil & NGL production (mbbls/day)		234.5			214.1			227.7			238.2			246.9			223.4			216.6			236.5
Natural gas (mmcf/day)		555.4			521.3			528.8			618.6			660.7			657.7			721.6			717.0
Total production (mboe/day)		327.0			301.0			315.8			341.3			357.0			333.0			336.9			356.0
Average sales prices
Light & Medium crude oil ($/bbl)		64.12			54.91			56.11			39.65			49.31			54.23			69.99			56.91
NGL ($/bbl)		46.47			35.62			36.68			31.89			42.46			43.18			51.97			45.29
Heavy crude oil ($/bbl)		36.30			35.04			34.88			18.12			28.71			36.51			50.21			32.97
Bitumen ($/bbl)		33.80			29.53			30.95			12.83			25.67			33.86			48.45			34.97
Natural gas ($/mcf)		5.65			3.99			3.46			4.41			5.51			5.76			6.09			5.96
Operating costs ($/boe)		13.92			15.15			13.90			13.31			14.51			15.52			15.72			14.87
Operating netbacks(2)
Lloydminster – Thermal Oil ($/bbl)(3)		22.02			19.72			24.61			10.02			18.77			22.06			33.52			22.68
Lloydminster – Non-Thermal Oil ($/boe)(3)		11.58			11.28			15.05			0.50			7.53			13.51			26.88			9.12
Cold Lake – Bitumen ($/bbl)(3)		21.34			20.04			26.55			5.28			13.91			17.75			5.89			10.18
Oil Sands – Bitumen ($/bbl)(3)		5.42			0.90			(26.52	)		(53.29	)		(56.39	)		(103.92	)		(119.67	)		—
Western Canada – Crude Oil ($/bbl)(3)		5.06			11.37			18.95			(1.94	)		8.96			14.97			26.06			8.81
Western Canada – NGL & natural gas ($/mcf)(4)		1.36			0.45			(0.56	)		0.36			0.64			1.08			1.00			0.88
Atlantic – Light Oil ($/bbl)(3)		40.49			22.83			28.55			27.82			31.36			36.51			46.81			43.21
Asia Pacific – Light Oil, NGL & natural gas ($/boe)(3)		61.09			47.77			59.21			61.11			68.15			67.70			69.60			68.19
Total ($/boe)(2)		22.32			15.70			17.30			9.68			17.28			20.72			28.93			21.45

Management’s Discussion and Analysis 2016

61

	2016								2015
Segmented Operational Information (continued)	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Upgrader
Synthetic crude oil sales (mbbls/day)		50.0		53.3		59.8		57.7		59.4		31.6		55.0		58.5
Total sales (mbbls/day)		66.9		69.7		76.5		78.3		80.7		42.5		73.2		81.0
Upgrading differential ($/bbl)		20.36		19.45		20.85		22.23		22.19		17.58		18.93		15.72
Canadian Refined Products
Fuel sales (million litres/day)		6.6		6.8		6.8		6.2		7.3		7.7		7.6		7.6
Refinery throughput
Lloydminster refinery (mbbls/day)		28.4		26.7		28.2		28.0		28.2		26.4		28.4		29.2
Prince George refinery (mbbls/day)		11.8		9.7		5.1		11.0		11.3		11.0		8.5		11.4
U.S. Refining and Marketing
Refinery throughput
Lima refinery (mbbls/day)		165.1		155.6		103.9		127.5		144.8		142.9		136.1		119.2
BP-Husky Toledo refinery (mbbls/day)(5)		78.8		58.4		41.2		69.4		72.8		68.0		75.5		56.3

⁽¹⁾ Adjusted net earnings (loss) and funds from operations are non-GAAP measures. Refer to Section 11.3 for a reconciliation to the GAAP measures.

⁽²⁾  Operating netback is a non-GAAP measure and is equal to gross revenue less royalties, production and operating costs and transportation costs on a per unit basis.. Refer to Section 11.3.

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

⁽⁴⁾  Includes associated co-products converted to mcfge.

⁽⁵⁾  BP-Husky Toledo Refinery throughput was revised in the first quarter of 2016 to reflect total throughput. Prior periods reflected crude throughput only and have been restated to conform with current presentation.

Significant Items Impacting Gross Revenues, Net Earnings (Loss) and Funds from Operations

Variations in the Company’s gross revenues, net earnings (loss) and funds from operations (non-GAAP measure) are primarily driven by changes in production volumes, commodity prices, commodity price differentials, refining crack spreads, foreign exchange rates and planned turnarounds. Weak crude oil and North American natural gas prices throughout 2016, resulted in significant declines in the Company’s gross revenues, net earnings and funds from operations (non-GAAP measure). Other significant items which impacted gross revenues, net earnings and funds from operations (non-GAAP measure) over the last eight quarters include:

• In 2016, the Company accrued business interruption and property damage insurance recoveries of $176 million associated with a fire that damaged the Company’s isocracker unit at Lima during the first quarter of 2015. To date, the Company has recorded $411 million in insurance recoveries.

• In the fourth quarter of 2016, the Company recognized after-tax property, plant and equipment net impairment reversal charges of $202 million related to crude oil and natural gas assets located in Western Canada. The impairment reversal was due to an acceleration of forecasted production and revised operational economics, based on recent production performance and market transactions. In addition, the Company recorded an exploration and evaluation land after-tax write-down of $41 million primarily related to Oil Sands assets.

• In the fourth quarter of 2016, the Company completed the sale of select assets in southern Alberta representing approximately 4,700 boe/day for gross proceeds of $24 million and after-tax gains of $37 million.

• In the fourth quarter of 2016, an additional well was brought into production at the South White Rose drill centre.

• In the third quarter of 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 and an after-tax gain of $1.32 billion. 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, of which the Company owns 35 percent, PAH owns 48.75 percent and CKI owns 16.25 percent.

• In the third quarter of 2016, the Company completed the sale of several packages of select legacy Western Canada crude and natural gas assets in Saskatchewan and Alberta representing approximately 5,000 boe/day for total gross proceeds of approximately $299 million, resulting in an after-tax gain of $167 million.

• In 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 to set the price at Cdn. $12.50- Cdn. $15.00 per thousand cubic feet (mcf ) at the 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.

• In the third quarter of 2016, the Company achieved first production at the North Amethyst Hibernia formation well.

• In the third quarter of 2016, the Company achieved first oil at the 4,500 bbls/day Edam West heavy oil thermal development.

• In the second quarter of 2016, U.S. Refining and Marketing throughput and sales volumes were lower due to major planned turnarounds at both the Lima and BP-Husky Toledo Refineries.

• In the second quarter of 2016, Prince George Refinery gross margins were lower due to a planned turnaround.

• In the second quarter of 2016, the demand for natural gas in North America was lower due to unseasonably mild weather conditions coupled with a temporary decline in natural gas demand from Canadian oil sands operations due to the wildfires in the Fort McMurray region of Alberta.

Management’s Discussion and Analysis 2016

62

• In the second quarter of 2016, the Company recorded an exploration and evaluation land after-tax write-down of $22 million relating to two exploration wells drilled in the Flemish Pass Basin which did not encounter economic quantities of hydrocarbons.

• In the second quarter of 2016, the Company completed the sale of several packages of select legacy Western Canada crude oil and natural gas assets in Saskatchewan and Alberta representing approximately 20,500 boe/day for total gross proceeds of approximately $791 million. As a part of one of the transactions, the Company obtained interests in lands with thermal development potential in the Lloydminster region. The Company recorded an after-tax loss of $184 million for the sale.

• In the second quarter of 2016, the Company completed the sale of royalty interests representing approximately 1,700 boe/day of Western Canada production. The sale proceeds include $165 million in cash and other considerations, including the transfer to the Company of royalty and working interests in select heavy oil properties in the Lloydminster area. The Company recorded an after-tax gain of $119 million for the sale.

• In the second quarter of 2016, first oil was achieved at the 10,000 bbls/day Vawn heavy oil thermal development.

• In the second quarter of 2016, the Company achieved first oil at the 10,000 bbls/day Edam East heavy oil thermal development.

• In the second quarter of 2016, the Company achieved first oil at the development of the Colony formation at the Tucker Thermal Project. This formation has similar characteristics to heavy oil thermal reservoirs in the Lloydminster region.

• In the first quarter of 2016, throughput decreased at the Upgrader primarily due to unscheduled maintenance.

• In 2015, the Company accrued business interruption and property damage insurance recoveries of $235 million associated with a fire that damaged the Company’s isocracker unit at Lima during the first quarter of 2015.

• In the fourth quarter of 2015, the Company recorded a pre-tax provision of $16 million in the U.S. Refining and Marketing business segment and a pre-tax provision of $6 million in the Infrastructure and Marketing business segment to bring inventory to net realizable value.

• In the third quarter of 2015, the Company recorded after-tax property, plant and equipment and goodwill impairment charges of $3,824 million related to crude oil and natural gas assets located in Western Canada. The after-tax impairment charge was the result of sustained declines in forecasted short and long-term crude oil and natural gas prices and management’s decision to reduce capital expenditures in these areas. In addition, the Company recorded an after-tax exploration and evaluation asset write-down of $167 million during the third quarter on certain Western Canada resource play assets and an associated $35 million after-tax work commitment penalty. The write-down was the result of management’s plan to withdraw from further exploration and evaluation due to lower estimated short and long-term crude oil and natural gas prices.

• In the third quarter of 2015, the Company derecognized approximately $46 million pre-tax of assets related to the cancellation of the West Mira drilling rig contract.

• In the third quarter of 2015, operations at the Company’s Upgrader were suspended for approximately eight weeks for unplanned maintenance to address repairs to the facility’s coke drums.

• In the second quarter of 2015, the Company recognized a deferred income tax expense of $157 million related to an increase in Alberta provincial tax rates.

• In the second quarter of 2015, the Company wrote-off approximately $46 million pre-tax of the carrying value of the isocracker unit at the Lima Refinery which was damaged by a fire in the first quarter of 2015.

• In the first quarter of 2015, the Company recognized a deferred income tax recovery of $203 million in its U.S. Refining and Marketing business segment related to the partial payment of the contribution payable to BP-Husky Refining LLC.

• In the first quarter of 2015, the Company was negatively impacted by unplanned outages at the Lima and BP-Husky Toledo refineries. The Lima Refinery was negatively impacted by an unplanned outage when a fire occurred in the isocracker unit in January 2015 and the BP-Husky Toledo Refinery was negatively impacted by unplanned maintenance to repair a damaged fluid catalytic cracking unit.

Management’s Discussion and Analysis 2016

63

Segmented Financial Information

	Upstream																								Downstream
	Exploration and Production(1)												Infrastructure and Marketing												Upgrading
2016 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4		Q3			Q2			Q1
Gross revenues		1,215			941			1,044			836			195			275			270			215			340		334			369			281
Royalties		(105	)		(56	)		(90	)		(54	)		—			—			—			—			—		—			—			—
Marketing and other		—			—			—			—			(9	)		5			18			(102	)		—		—			—			—
Revenues, net of royalties		1,110			885			954			782			186			280			288			113			340		334			369			281
Expenses
Purchases of crude oil and products		—			6			14			12			186			273			227			171			224		225			222			137
Production, operating and transportation expenses		438			429			442			451			3			2			7			8			49		43			40			36
Selling, general and administrative expenses		81			57			52			42			2			1			1			1			2		—			1			1
Depletion, depreciation, amortization and impairment		237			474			542			562			—			1			6			6			21		27			27			28
Exploration and evaluation expenses		78			17			76			17			—			—			—			—			—		—			—			—
Loss (gain) on sale of assets		(55	)		(236	)		96			2			3			(1,442	)		—			—			—		—			—			—
Other – net		29			18			9			(2	)		4			(3	)		(1	)		(3	)		—		—			(1	)		—
		808			765			1,231			1,084			198			(1,168	)		240			183			296		295			289			202
Earnings from operating activities		302			120			(277	)		(302	)		(12	)		1,448			48			(70	)		44		39			80			79
Share of equity investment gain (loss)		2			(1	)		(1	)		(1	)		36			(20	)		—			—			—		—			—			—
Net foreign exchange gains (losses)		—			—			—			—			—			—			—			—			—		—			—			—
Finance income		2			3			—			—			—			—			—			—			—		—			—			—
Finance expenses		(34	)		(35	)		(36	)		(40	)		—			—			—			—			—		(1	)		—			—
		(32	)		(32	)		(36	)		(40	)		—			—			—			—			—		(1	)		—			—
Earnings (loss) before income tax		272			87			(314	)		(343	)		24			1,428			48			(70	)		44		38			80			79
Provisions for (recovery of ) income taxes
Current		12			(9	)		6			(109	)		—			—			—			—			—		—			—			—
Deferred		62			33			(92	)		16			6			122			13			(19	)		12		11			22			21
		74			24			(86	)		(93	)		6			122			13			(19	)		12		11			22			21
Net earnings (loss)		198			63			(228	)		(250	)		18			1,306			35			(51	)		32		27			58			58
Capital expenditures(3)		274			173			250			175			3			(5	)		24			32			19		13			13			6
Total assets		19,098			18,654			19,008			20,454			1,582			1,407			1,732			1,647			1,076		1,082			1,151			1,131

⁽¹⁾ Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production.

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices.

⁽³⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

Management’s Discussion and Analysis 2016

64

Downstream (continued)																								Corporate and Eliminations(2)												Total
Canadian Refined Products												U.S. Refining and Marketing
Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	603			678			585			435			1,890			1,642			1,337			1,126			(369	)		(355	)		(362	)		(213	)		3,874			3,515			3,243			2,680
	—			—			—			—			—			—			—			—			—			—			—			—			(105	)		(56	)		(90	)		(54	)
	—			—			—			—			—			—			—			—			—			—			—			—			(9	)		5			18			(102	)
	603			678			585			435			1,890			1,642			1,337			1,126			(369	)		(355	)		(362	)		(213	)		3,760			3,464			3,171			2,524
	475			516			440			339			1,617			1,448			1,083			1,040			(369	)		(355	)		(362	)		(213	)		2,133			2,113			1,624			1,486
	66			62			64			49			144			127			127			137			—			—			—			—			700			663			680			681
	23			6			7			7			4			3			3			3			63			39			82			63			175			106			146			117
	27			26			25			24			96			88			77			81			24			22			20			21			405			638			697			722
	—			—			—			—			—			—			—			—			—			—			—			—			78			17			76			17
	—			(2	)		(1	)		—			—			—			—			—			—			—			—			—			(52	)		(1,680	)		95			2
	(1	)		(8	)		—			(1	)		(1	)		—			(50	)		(125	)		(4	)		(17	)		65			66			27			(10	)		22			(65	)
	590			600			535			418			1,860			1,666			1,240			1,136			(286	)		(311	)		(195	)		(63	)		3,466			1,847			3,340			2,960
	13			78			50			17			30			(24	)		97			(10	)		(83	)		(44	)		(167	)		(150	)		294			1,617			(169	)		(436	)
	—			—			—			—			—			—			—			—			—			—			—			—			38			(21	)		(1	)		(1	)
	—			—			—			—			—			—			—			—			8			1			(9	)		13			8			1			(9	)		13
	—			—			—			—			—			—			—			—			5			2			—			5			7			5			—			5
	(2	)		(2	)		(1	)		(2	)		(1	)		—			(1	)		(1	)		(63	)		(60	)		(58	)		(64	)		(100	)		(98	)		(96	)		(107	)
	(2	)		(2	)		(1	)		(2	)		(1	)		—			(1	)		(1	)		(50	)		(57	)		(67	)		(46	)		(85	)		(92	)		(105	)		(89	)
	11			76			49			15			29			(24	)		96			(11	)		(133	)		(101	)		(234	)		(196	)		247			1,504			(275	)		(526	)
	—			—			—			—			—			—			—			—			4			24			23			48			16			15			29			(61	)
	3			21			13			4			10			(8	)		35			(4	)		(48	)		(80	)		(99	)		(25	)		45			99			(108	)		(7	)
	3			21			13			4			10			(8	)		35			(4	)		(44	)		(56	)		(76	)		23			61			114			(79	)		(68	)
	8			55			36			11			19			(16	)		61			(7	)		(89	)		(45	)		(158	)		(219	)		186			1,390			(196	)		(458	)
	12			3			29			8			67			107			267			182			16			18			12			7			391			309			595			410
	1,410			1,419			1,458			1,399			7,017			6,822			6,866			6,444			2,077			2,179			763			821			32,260			31,563			30,978			31,896

Management’s Discussion and Analysis 2016

65

	Upstream																								Downstream
	Exploration and Production(1)												Infrastructure and Marketing												Upgrading
2015 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues		1,189			1,253			1,577			1,355			311			250			337			366			364			190			418			347
Royalties		(85	)		(83	)		(134	)		(130	)		—			—			—			—			—			—			—			—
Marketing and other		—			—			—			—			(10	)		23			(44	)		69			—			—			—			—
Revenues, net of royalties		1,104			1,170			1,443			1,225			301			273			293			435			364			190			418			347
Expenses
Purchases of crude oil and products		7			8			17			9			269			217			302			335			212			162			310			238
Production, operating and transportation expenses		524			519			521			512			12			7			9			9			44			40			42			43
Selling, general and administrative expenses		57			51			60			69			2			2			1			2			1			1			1			1
Depletion, depreciation, amortization and impairment		641			5,920			713			719			8			6			6			5			28			26			26			26
Exploration and evaluation expenses		39			308			43			57			—			—			—			—			—			—			—			—
Loss (gain) on sale of assets		(4	)		(15	)		—			2			—			—			—			—			—			—			—			—
Other – net		(17	)		(33	)		33			(17	)		(3	)		(4	)		3			(1	)		—			—			—			(11	)
		1,247			6,758			1,387			1,351			288			228			321			350			285			229			379			297
Earnings from operating activities		(143	)		(5,588	)		56			(126	)		13			45			(28	)		85			79			(39	)		39			50
Share of equity investment gain (loss)		(4	)		(1	)		—			—			—			—			—			—			—			—			—			—
Net foreign exchange gains (losses)		—			—			—			—			—			—			—			—			—			—			—			—
Finance income		—			1			1			1			—			—			—			—			—			—			—			—
Finance expenses		(36	)		(35	)		(35	)		(36	)		—			—			—			—			(1	)		—			—			—
		(36	)		(34	)		(34	)		(35	)		—			—			—			—			(1	)		—			—			—
Earnings (loss) before income taxes		(183	)		(5,623	)		22			(161	)		13			45			(28	)		85			78			(39	)		39			50
Provisions for (recovery of) income taxes
Current		111			27			(14	)		(165	)		(5	)		5			40			182			7			(2	)		(6	)		(16	)
Deferred		(160	)		(1,547	)		18			123			8			8			(47	)		(160	)		14			(8	)		17			29
		(49	)		(1,520	)		4			(42	)		3			13			(7	)		22			21			(10	)		11			13
Net earnings (loss)		(134	)		(4,103	)		18			(119	)		10			32			(21	)		63			57			(29	)		28			37
Capital expenditures(3)(4)		378			597			571			723			42			77			30			19			12			19			7			8
Total assets		21,103			21,296			26,550			26,488			1,699			1,814			1,857			1,830			1,141			1,098			1,107			1,209

⁽¹⁾  Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production.

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices.

⁽³⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

⁽⁴⁾  2015 Exploration and Production capital expenditures were revised during the fourth quarter of 2015 to exclude capital expenditures incurred by the Husky-CNOOC Madura Ltd joint venture, which are classified as contribution to joint venture investing activities on the Company’s Consolidated Statements of Cash Flows.

Management’s Discussion and Analysis 2016

66

Downstream (continued)																								Corporate and Eliminations(2)												Total
Canadian Refined Products												U.S. Refining and Marketing
Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	699			839			747			601			1,692			1,973			1,955			1,725			(342	)		(242	)		(464	)		(377	)		3,913			4,263			4,570			4,017
	—			—			—			—			—			—			—			—			—			—			—			—			(85	)		(83	)		(134	)		(130	)
	—			—			—			—			—			—			—			—			—			—			—			—			(10	)		23			(44	)		69
	699			839			747			601			1,692			1,973			1,955			1,725			(342	)		(242	)		(464	)		(377	)		3,818			4,203			4,392			3,956
	544			655			599			483			1,583			1,784			1,549			1,539			(342	)		(242	)		(464	)		(377	)		2,273			2,584			2,313			2,227
	55			57			63			63			120			119			107			128			—			—			—			—			755			742			742			755
	8			7			6			10			2			3			2			3			32			(15	)		16			20			102			49			86			105
	26			26			26			25			76			74			114			69			22			22			20			20			801			6,074			905			864
	—			—			—			—			—			—			—			—			—			—			—			—			39			308			43			57
	(2	)		(1	)		(2	)		—			—			—			—			—			—			—			—			—			(6	)		(16	)		(2	)		2
	—			—			—			1			(80	)		(65	)		(91	)		—			1			(3	)		—			—			(99	)		(105	)		(55	)		(28	)
	631			744			692			582			1,701			1,915			1,681			1,739			(287	)		(238	)		(428	)		(337	)		3,865			9,636			4,032			3,982
	68			95			55			19			(9	)		58			274			(14	)		(55	)		(4	)		(36	)		(40	)		(47	)		(5,433	)		360			(26	)
	—			—			—			—			—			—			—			—			—			—			—			—			(4	)		(1	)		—			—
	—			—			—			—			—			—			—			—			(11	)		(14	)		6			62			(11	)		(14	)		6			62
	—			—			—			—			—			—			—			—			27			3			1			1			27			4			2			2
	(2	)		(1	)		(2	)		(1	)		(1	)		—			(1	)		(1	)		(48	)		(48	)		(36	)		(14	)		(88	)		(84	)		(74	)		(52	)
	(2	)		(1	)		(2	)		(1	)		(1	)		—			(1	)		(1	)		(32	)		(59	)		(29	)		49			(72	)		(94	)		(66	)		12
	66			94			53			18			(10	)		58			273			(15	)		(87	)		(63	)		(65	)		9			(123	)		(5,528	)		294			(14	)
	(67	)		32			24			17			(3	)		(16	)		24			10			40			28			27			26			83			74			95			54
	84			(7	)		(10	)		(12	)		(2	)		38			77			(219	)		(81	)		6			24			(20	)		(137	)		(1,510	)		79			(259	)
	17			25			14			5			(5	)		22			101			(209	)		(41	)		34			51			6			(54	)		(1,436	)		174			(205	)
	49			69			39			13			(5	)		36			172			194			(46	)		(97	)		(116	)		3			(69	)		(4,092	)		120			191
	14			6			5			5			182			100			95			48			13			18			19			17			641			817			727			820
	1,448			1,568			1,634			1,622			6,784			6,776			6,316			6,226			881			993			1,018			968			33,056			33,545			38,482			38,343

Management’s Discussion and Analysis 2016

67

Exhibit No.	Description
23.1	Consent of KPMG LLP, independent registered public accounting firm.
23.2	Consent of Sproule Unconventional Limited, independent engineers.
23.3	Consent of Richard Leslie, P. Eng, internal qualified reserves evaluator.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
32.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) or Rule 15d-14(b)and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
99.1	Supplemental Disclosures of Oil and Gas Activities.
99.2	Amended Code of Business Conduct.