2019

 

 

 

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, 2019

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

 

Title of each Class		Trading Symbol(s)		Name of each exchange on which registered
N/A		N/A		N/A

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:

1,005,121,738 Common Shares outstanding as of December 31, 2019

10,435,932 Cumulative Redeemable Preferred Shares, Series 1 outstanding as of December 31, 2019

1,564,068 Cumulative Redeemable Preferred Shares, Series 2 outstanding as of December 31, 2019

10,000,000 Cumulative Redeemable Preferred Shares, Series 3 outstanding as of December 31, 2019

8,000,000 Cumulative Redeemable Preferred Shares, Series 5 outstanding as of December 31, 2019

6,000,000 Cumulative Redeemable Preferred Shares, Series 7 outstanding as of December 31, 2019

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

☒  Yes            ☐  No

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

☒  Yes            ☐  No

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

Emerging growth company  ☐

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

This 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. 333-236603); Form S-8 (File No. 333-187135).

 

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

 

 

 

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, 2019 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, 2019 and December 31, 2018, including the auditors’ report with respect thereto, are 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, 2019 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, 2019, 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, 2019, 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 for the years ended December 31, 2019 and 2018, which are 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, 2019, 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 Husky’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, 2019, 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. On April 25, 2019, Husky amended its Code of Business Conduct effective as of April 25, 2019, 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, 2019. A copy of such amended Code of Business Conduct was posted on Husky’s website (together with a disclosure of the nature of the amendments) promptly after the amendments became effective.

The following is a general summary of the nature of the amendments:

 

i.

Updates to the section on lobbying to provide additional guidance on which activities constitute lobbying and when and to whom to report lobbying activities. When originally drafted, this section was Canadian centric, so updates were made to reflect other lobbying laws to which Husky is subject.

 

ii.

Updates to the section on accepting hospitality, promotional offerings and other business courtesies to align with, and reflect changes to, Husky’s Anti-Bribery and Anti-Corruption Policy. This included updating the definition of “things of value” and the rules regarding the acceptance or giving of bona fide hospitality, promotional offerings and other business courtesies.

 

iii.

Updates to the section on privacy to provide additional guidance on handling of personal information and to reflect Taiwanese privacy law requirements.

A copy of the amended Code of Business Conduct is available to any person without charge, upon request made in writing to Husky’s principal executive office, Attention: Corporate Secretary.

In the fiscal year ended December 31, 2019, Husky did not grant 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. 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, 2019, 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, 2019, 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, 2019, which is included as Document C of this Annual Report on Form 40-F.

Interactive Data File

See Exhibit 101 to this Annual Report on Form 40-F for the fiscal year ended December 31, 2019.

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. 333-236603) 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 27^th day of February, 2020

 

 

Document A

Form 40-F

Annual Information Form

For the Year Ended December 31, 2019

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2019

February 27, 2020

TABLE OF CONTENTS

 

NOTE TO READER			1
ABBREVIATIONS AND GLOSSARY OF TERMS			1
EXCHANGE RATE INFORMATION			6
CORPORATE STRUCTURE			6
GENERAL DEVELOPMENT OF HUSKY			7
DESCRIPTION OF HUSKY’S BUSINESS			10
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION			21
INDUSTRY OVERVIEW			42
ENVIRONMENTAL, SOCIAL AND GOVERNANCE CONSIDERATIONS			50
RISK FACTORS			56
HUSKY EMPLOYEES			63
DIVIDENDS			63
DESCRIPTION OF CAPITAL STRUCTURE			65
MARKET FOR SECURITIES			68
DIRECTORS AND OFFICERS			71
LEGAL PROCEEDINGS			79
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS			79
TRANSFER AGENTS AND REGISTRARS			79
INTERESTS OF EXPERTS			79
ADDITIONAL INFORMATION			79
READER ADVISORIES			80
APPENDIX A - AUDIT COMMITTEE MANDATE			84
APPENDIX B - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES AUDITOR			88
APPENDIX C - REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE			89
APPENDIX D - INDEPENDENT QUALIFIED RESERVES AUDITOR AUDIT OPINION			90

 

NOTE TO READER

Unless otherwise indicated, in this Annual Information Form (“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 indicated, the information contained in this AIF is presented as at or for the year ended December 31, 2019, and all financial information included and incorporated by reference in this AIF is determined using International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board.

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

See also “Reader Advisories” on page 80 of this AIF.

ABBREVIATIONS AND GLOSSARY OF TERMS

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

 

Units of Measure
bbl		barrel
bbl/day		barrel per calendar day
bbls/day		barrels per calendar day
bcf		billion cubic feet
bcf/day		billion cubic feet per calendar day
boe		barrels of oil equivalent
boe/day		barrels of oil equivalent per calendar day
GJ		gigajoule
kt		kilotonne
long ton/day		imperial measurement of a metric tonne per calendar day
m3		cubic metres
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		tonnes of carbon dioxide equivalent

abandonment and reclamation costs

All costs associated with the process of restoring the Company’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.

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.

 

Husky Energy Inc. | Annual Information Form 2019 | 1

Asphalt Refinery

The asphalt refinery owned by the Company and located in Lloydminster, Alberta.

barrel

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

bitumen

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.

Board

The Board of Directors of the Company.

BP-Husky Toledo Refinery

The crude oil refinery owned 50% by the Company and 50% by BP Corporation North America Inc. and located in Toledo, Ohio.

CHOPS

Cold heavy oil production with sand.

CO₂e

Carbon dioxide equivalent.

conventional natural gas

Natural gas that has been generated elsewhere and has migrated as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be formed by localized structural, depositional or erosional geological features.

C-NLOPB

Canada-Newfoundland Offshore Petroleum Board

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 or EOR

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 or EL

A licence with respect to the Canadian offshore or the Northwest 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.

 

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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.

FPSO

Floating production, storage and offloading vessel.

GAAP

Generally accepted accounting principles, consistently applied.

gross/net acres and gross/net wells

Gross refers to the total number of acres or wells, as the context requires, in which a working interest is owned. Net refers to the sum of the fractional working interests owned by a company.

gross reserves and gross production

A company’s working interest share of reserves or production, as the context requires, before deduction of royalties.

GSA

Gas sales agreement.

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.

HMLP

Husky Midstream Limited Partnership.

HS&E

Health, safety and environment.

light crude oil

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

Lima Refinery

The crude oil refinery owned by the Company and located in Lima, Ohio.

liquefied petroleum gas

Liquefied propanes and butanes, separately or in mixtures.

medium crude oil

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

natural gas

A naturally occurring hydrocarbon gas and other gases.

natural gas liquids or NGL

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 and butane and condensates and combinations thereof.

net revenue

Gross revenue less royalties.

 

Husky Energy Inc. | Annual Information Form 2019 | 3

NL

Newfoundland and Labrador.

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

Represents, as it relates to the Company’s operations in Indonesia, a development plan on one or more oil and gas fields in an integrated and optimal plan for the production of hydrocarbon reserves considering technical, economical and environmental aspects. An initial Plan of Development in a development area needs both SKK Migas and the Minister of Energy and Mineral Resources approvals. 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 or PSC

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.

Scope 1 emissions

Direct emissions from sources that are owned or controlled by the Company, as prescribed by the U.S. Environmental Protection Agency.

Scope 2 emissions

Indirect emissions from sources that are owned or controlled by the Company, as prescribed by the U.S. Environmental Protection Agency.

SEC

United States Securities and Exchange Commission.

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.

Significant Discovery Declaration

A discovery indicated by the first well on a geological feature that demonstrates by flow testing the existence of hydrocarbons in that feature and, having regard to geological and engineering factors, suggests the existence of an accumulation of hydrocarbons that has potential for sustained production.

Significant Discovery Licence

The document of “title” by which an interest owner can continue to hold rights to a discovery area while the extent of that discovery is determined and, if it has potential to be brought into commercial production in the future, until commercial development becomes viable. A significant discovery licence is effective from the application date and remains in force for so long as the relevant declaration of significant discovery is in force, or until a production licence is issued for the relevant lands.

 

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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 or SAGD

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.

stratigraphic test well

A hole drilled to delineate or derisk the geology, and may include the cutting of cores, to aid in exploring and developing for oil and gas and usually drilled without the intent of being completed for production.

sulphur

An element that occurs in natural gas and petroleum.

Superior Refinery

The crude oil refinery owned by the Company and located in Superior, Wisconsin.

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.

Upgrader

The heavy oil upgrading facility owned and operated by the Company and located in Lloydminster, Saskatchewan.

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

Two-dimensional seismic imaging uses seismic wave data recorded on one receiver line on the ground, to output a single cross-section of seismic data that is used to detect geologic variations in the subsurface.

3-D seismic survey

Three-dimensional seismic imaging uses seismic wave data recorded simultaneously on a series of parallel receiver lines on the ground, to output a three-dimensional volume of seismic data that is used to detect geologic variations in the subsurface.

2018 U.S. Shelf Prospectus and Registration Statement

The universal short form base shelf prospectus filed by the Company on January 29, 2018 with the Alberta Securities Commission and the related U.S. registration statement (containing such prospectus) filed with the SEC that became effective on January 30, 2018.

 

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EXCHANGE RATE INFORMATION

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

 

		Year ended December 31,
Exchange Rate Information (Cdn$ per US$)		2019				2018				2017
Year-end(1)			1.297				1.365				1.252
Low			1.297				1.228				1.213
High			1.359				1.365				1.374
Average			1.327				1.296				1.298

 

(1)	The year-end exchange rates were quoted by the Thomson Reuters WM/R for the noon rate 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.

CORPORATE STRUCTURE

Incorporation and Organization

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’s registered office and head and principal office are located at 707 - 8^th Avenue S.W., Calgary, Alberta, T2P 1H5.

Intercorporate Relationships

The following table lists Husky’s significant subsidiaries and jointly-controlled entities and their respective places of incorporation, continuance or organization, as the case may be, as at December 31, 2019. All of the entities listed below, except as otherwise indicated, are 100% beneficially owned, or controlled or directed, directly or indirectly, by Husky.

 

Significant Subsidiaries and Joint Operations(1)		Jurisdiction
Husky Oil Operations Limited		Alberta
Husky Energy International Corporation		Alberta
Lima Refining Company		Delaware
Husky Marketing and Supply Company		Delaware
Husky Oil Limited Partnership		Alberta
Husky Terra Nova Partnership(2)		Alberta
Husky Downstream General Partnership(2)		Alberta
Husky Energy Marketing Partnership		Alberta
Sunrise Oil Sands Partnership (50%)		Alberta
BP-Husky Refining LLC (50%)		Delaware

 

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

(2)	Dissolved effective January 1, 2020, and assets were transferred to 2188787 Alberta ULC, a wholly-owned subsidiary of Husky.

 

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GENERAL DEVELOPMENT OF HUSKY

Three-year History of Husky

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

2017

On March 10, 2017, the Company issued $750 million of 3.60% notes due March 10, 2027 by way of a prospectus supplement dated March 7, 2017 to its base shelf prospectus.

On April 13, 2017, the Company announced that it had signed a PSC for Block 16/25 in the Pearl River Mouth Basin in the South China Sea. Under the PSC, Husky has an obligation to drill two exploration wells within the first three years.

On May 5, 2017, the Company announced that, during the first quarter of 2017, it had commenced production from a new eight-well pad at the Tucker Thermal Project in the Cold Lake region of Alberta and from a new infill well at North Amethyst offshore NL.

On May 29, 2017, the Company announced that, together with its partners, it would be moving forward with the West White Rose Project in the Jeanne d’Arc Basin offshore NL, using a fixed wellhead platform tied back to the SeaRose FPSO.

Also in May 2017, the Company announced a new discovery at Northwest White Rose. The White Rose A-78 well was drilled approximately 11 kilometres northwest of the SeaRose FPSO in the first quarter of 2017 and delineated a light oil column of more than 100 metres (gross). The Company has a 93.23% working interest in the well.

On July 21, 2017, the Company announced that the construction and installation of the shallow water jackets and subsea pipelines for the MDA-MBH fields in the Madura Strait were completed. The contract for a leased floating production unit was signed, and planning for the build commenced.

On September 15, 2017, the Company repaid the maturing 6.20% notes issued under a trust indenture dated September 11, 2007. The amount paid to note holders was $365 million, including $11 million of interest.

On October 26, 2017, the Company announced that, during the third quarter of 2017, gas production from the BD Project commenced and was sold from the onshore gas distribution facility in East Java under a fixed price GSA.

Also in October 2017, the Company announced that the GSA for future gas production from Liuhua 29-1, the third deepwater gas field at the Liwan Gas Project, was signed. The project was sanctioned in the fourth quarter of 2017.

On November 8, 2017, the Company completed the purchase of the Superior Refinery from Calumet Specialty Products Partners, L.P. for $670 million (US$527 million). The acquisition included the Superior Refinery’s associated logistics assets, including two asphalt terminals, 3.6 mmbbls of crude and product storage and a fuels and asphalt marketing business. See “Description of Husky’s Business - Integrated Corridor - U.S. Refining and Marketing - Superior Refinery”.

In November 2017, the Company sanctioned two new 10,000 bbl/day thermal projects at Westhazel and Edam Central.

Also in November 2017, the C-NLOPB announced that the Company was the successful bidder on a parcel of land in its 2017 land sale (50% Husky working interest). The lands cover an area of 121,453 hectares in the Jeanne d’Arc Basin and are adjacent to the Company’s other exploration licences in the basin.

Also in November 2017, the Company’s participation in the Wenchang oilfields petroleum contract expired, with the Company not being entitled to any further production rights.

During 2017, the Company completed the sale of select assets in Western Canada, representing approximately 20,200 boe/day for gross proceeds of approximately $185 million.

Also during 2017, regulatory approval was received for the three Lloyd thermal projects sanctioned in late 2016, Dee Valley, Spruce Lake North and Spruce Lake Central.

Also during 2017, the Company and Imperial Oil closed their previously announced transaction to create a single expanded truck transport network of approximately 160 sites.

 

Husky Energy Inc. | Annual Information Form 2019 | 7

2018

On January 17, 2018, the Company announced that it would begin taking steps to suspend operations of the SeaRose FPSO and associated production facilities offshore NL to comply with an order received from the C-NLOPB related to an iceberg management incident that occurred in March 2017.

On January 26, 2018, the Company announced that the C-NLOPB had lifted the notice to suspend operations of the SeaRose FPSO and associated facilities and that the Company would resume operations.

On March 1, 2018, the Company announced the establishment of a quarterly cash dividend of $0.075 per common share.

On April 26, 2018, a fire occurred at the Superior Refinery and operations were suspended.

On May 18, 2018, the Company announced that it had drilled a successful exploration well on Block 15/33 in the South China Sea, signed two PSCs for Block 22/11 and Block 23/07 in the Beibu Gulf area of the South China Sea and made a discovery at the White Rose A-24 exploration well offshore NL.

On July 26, 2018, the Company announced that the Board had approved an increase in the quarterly cash dividend to $0.125 per common share.

During the third quarter of 2018, the BD Project achieved total daily sales targets of 100 mmcf/day of conventional natural gas (40 mmcf/day Husky working interest) and 6,000 bbls/day of associated NGL (2,400 bbls/day Husky working interest).

On October 2, 2018, the Company announced that it had commenced an unsolicited offer to acquire all of the outstanding common shares of MEG Energy Corp. (“MEG”).

In October 2018, the Tucker Thermal Project reached nameplate capacity of 30,000 bbls/day.

Also in October 2018, the Rush Lake 2 thermal project achieved first production, with nameplate capacity of 10,000 bbls/day achieved in November 2018.

In November 2018, the Company shut in oil production at the White Rose field due to operational safety concerns resulting from severe weather and an oil release on November 16.

Also in November 2018, the Spruce Lake East thermal project in Saskatchewan was sanctioned.

In December 2018, the Sunrise Energy Project reached its nameplate capacity of 60,000 bbls/day (30,000 bbls/day Husky working interest).

2019

On January 8, 2019, the Company announced that it would be undertaking a strategic review and potentially selling its Canadian Retail and Commercial Fuels Network and the Prince George Refinery.

On January 16, 2019, the Company’s unsolicited offer to acquire all of the outstanding common shares of MEG expired with the minimum tender condition not having been met. The Company did not extend the offer due to a lack of support from the MEG board of directors and MEG shareholders.

On March 15, 2019, the Company issued US$750 million of 4.400% notes maturing on April 15, 2029 by way of a prospectus supplement dated March 13, 2019 to the 2018 U.S. Shelf Prospectus and Registration Statement.

On January 30, 2019, partial production resumed at the White Rose field following the shut-in of production announced in November 2018.

In the first quarter of 2019, regulatory approval was received for the Spruce Lake East thermal project.

On June 12, 2019, the Company entered guilty pleas on federal and provincial charges related to a 2016 oil spill in Saskatchewan and agreed to pay fines totaling $3.82 million.

On August 16, 2019, the Company announced that it would resume full production at the White Rose field.

On August 26, 2019, the Company announced that it had commenced production at its 10,000 barrel-per-day Dee Valley thermal project in Saskatchewan.

On September 30, 2019, the Company announced that it had received the required permit approvals to begin construction activities at the Superior Refinery following the April 2018 fire, and that the rebuild would take place over the following two years.

 

Husky Energy Inc. | Annual Information Form 2019 | 8

On November 1, 2019, the Company announced the closing of the sale of the Prince George Refinery to Tidewater Midstream and Infrastructure Ltd. (“Tidewater”) for $215 million in cash plus a closing adjustment of approximately $53.5 million.

On December 20, 2019, production operations on the Terra Nova FPSO were safely shut-in in response to a C-NLOPB order citing insufficient redundancy of fire water pumps. See “Description of Husky’s Business - Offshore - Atlantic - Terra Nova Field”.

 

Husky Energy Inc. | Annual Information Form 2019 | 9

DESCRIPTION OF HUSKY’S BUSINESS

Overview

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. For the year ended December 31, 2019, the Company’s business was conducted predominantly through two major business segments: Upstream and Downstream.

Upstream operations include exploration for, and development and production of, crude oil, bitumen, conventional natural gas and NGL (“Exploration and Production”) and marketing of the Company’s and other producers’ crude oil, conventional natural gas, NGL, sulphur and petroleum coke, pipeline transportation, the blending of crude oil and conventional natural gas, and storage of crude oil, diluent and conventional 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 China and Indonesia (“Asia Pacific”) and offshore the east coast of Canada (“Atlantic”) (Asia Pacific and Atlantic collectively, “Offshore”).

Downstream operations include upgrading of heavy crude oil feedstock into synthetic crude oil in Canada (“Upgrading”), refining crude oil in Canada, marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products and production of ethanol (“Canadian Refined Products”). It also includes refining in the U.S. of primarily crude oil to produce and market asphalt, 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 are grouped together as the Downstream business segment due to the similar nature of their products and services.

Effective January 1, 2020, the Company’s businesses were reorganized under two new business segments: (i) an integrated Canada-U.S. Upstream and Downstream corridor (“Integrated Corridor”); and (ii) production located offshore the east coast of Canada ( “Atlantic”) and offshore China and Indonesia ( “Asia Pacific” and collectively with Atlantic, “Offshore”). The Company will no longer operate under Upstream and Downstream business segments.

Integrated Corridor

The Company’s business in the Integrated Corridor includes: crude oil, bitumen, conventional natural gas, NGL and ethanol production from Western Canada; marketing and transportation of the Company’s and other producers’ production; the Upgrader and Asphalt Refinery; Husky Midstream Limited Partnership (35% working interest and operatorship); the Lima Refinery, the BP-Husky Toledo Refinery (50% working interest) and the Superior Refinery in the U.S. Midwest; and the marketing of refined petroleum products including gasoline, diesel and ethanol blended fuels through petroleum outlets. Conventional natural gas production from the Western Canada portfolio is closely aligned with the Company’s energy requirements for refining and thermal bitumen production and acts as a natural hedge.

Offshore

The Company’s Offshore business includes operations, development and exploration in Asia Pacific and Atlantic.

Corporate Strategy

The Company’s business strategy is to generate returns from investing in a deep portfolio of projects and other opportunities across the Integrated Corridor and Offshore businesses. These investments are intended to provide for increasing margins, funds from operations and earnings. A strong balance sheet, deep physical integration and largely fixed price contracts in Asia Pacific provide resilience to market volatility while preserving upside exposure to rising commodity prices.

Integrated Corridor

Thermal and Non-Thermal Developments

Heavy Oil and Bitumen

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. The majority of the Company’s operations are 100% working interest. The Company’s operations are supported by a network of facilities and pipelines that transport heavy crude oil and bitumen from the field locations to the Asphalt Refinery, the Upgrader and the Company’s other assets in the Integrated Corridor business segment, thus providing full integration.

Production of heavy crude oil and bitumen from the Lloydminster area uses a variety of technologies, including SAGD, CHOPS, horizontal wells, waterflooded fields and non-thermal EOR.

 

Husky Energy Inc. | Annual Information Form 2019 | 10

Lloydminster Thermal Projects

Lloydminster bitumen production consists of 10 thermal plants located in the Lloydminster region of Saskatchewan: Bolney/Celtic, Dee Valley, Edam East, Edam West, Paradise Hill, Pikes Peak South, Rush Lake 1 & 2, Sandall and Vawn. Each plant has a number of production pads and utilizes SAGD technology. Production in 2019 from Lloydminster thermal projects averaged 80,500 bbls/day. Saskatchewan thermal production is not impacted by Alberta government-mandated production curtailment.

The Company is phasing execution of its long-life thermal projects to optimize capital efficiency and project execution. In 2018, the Company completed two land deals to create two thermal hubs, one at Spruce Lake and one at Dee Valley. This has resulted in the acceleration of the Spruce Lake East project. The Edam Central project is now expected to be completed in 2022.

The following table shows major projects and their status as at December 31, 2019:

 

Project Name		Nameplate Capacity (bbls/day)		Expected Project Production Date		Project Status
Dee Valley		10,000		On production August 2019		First steam was achieved on June 30, 2019, with first oil on August 24, 2019. Reached nameplate capacity on September 30, 2019.
Spruce Lake Central(1)		10,000		Mid-Year 2020		Central Processing Facility (“CPF”) construction is complete and module setting on well pads has begun. Overall project is 90% complete.
Spruce Lake North		10,000		Around the end of 2020		CPF fabrication and module setting is complete. The overall project is 50% complete.
Spruce Lake East		10,000		Around the end of 2021		Regulatory approvals have been received, and lease construction is complete. Procurement and fabrication programs are in progress.
Edam Central		10,000		2022		Regulatory approvals have been received.
Dee Valley 2		10,000		2023		Project sanctioned in November 2019, and regulatory approvals have been received.

 

(1)	Previously expected to start production by the second half of 2020.

In February 2019, the Pike’s Peak thermal bitumen plant was closed down as it reached the end of its useful life. The plant achieved first production in September 1981 and produced 78 mmbbls over its useful life.

Tucker Thermal Project

The Tucker Thermal Project is a SAGD oil sands project located 30 kilometres northwest of Cold Lake, Alberta. It commenced bitumen production at the end of 2006.

Work to debottleneck the CPF and field was completed in 2018. Subsequently, production ramped up and nameplate capacity of 30,000 bbls/day was achieved in October 2018. Total annual production in 2019 averaged 23,700 bbls/day and was impacted by the government-mandated production quotas in Alberta. The Company plans to drill two new sustainment pads in 2020/21.

A major plant turnaround is scheduled for the CPF and field in the fourth quarter of 2020.

Cold and EOR

Production in Cold and EOR consists of a combination of production technologies, including CHOPS and horizontal wells and EOR projects.

In 2018, the Company sanctioned a full field polymer injection project at Aberfeldy, and injection began in 2019.

During 2019, the Company operated three carbon dioxide (“CO₂”) injection EOR pilot projects and a CO₂ capture and liquefaction plant at the Lloydminster Ethanol Plant. The liquefied CO₂ is used in the ongoing EOR piloting program. The Company is also piloting several types of CO₂ capture technology at its Pikes Peak South facility in Saskatchewan.

Total annual production in 2019 averaged 34,400 bbls/day and was also impacted by the government-mandated production quotas in Alberta.

 

Husky Energy Inc. | Annual Information Form 2019 | 11

Sunrise Energy Project

On March 31, 2008, Husky and BP Corporation North America Inc. (“BP”) completed a transaction that created an integrated North American oil sands and refining businesses. The businesses are 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 a SAGD oil sands project located in the Athabasca region of northern Alberta. During the fourth quarter of 2018 the project reached its nameplate capacity of 60,000 bbls/day.

At the end of 2019, there were 81 producing well pairs. Five well pairs and six infills have been drilled and are ready for production once government-mandated production quotas are lifted. Total annual production in 2019 averaged 49,200 bbls/day (24,600 bbls/day Husky working interest), and was impacted by the government-mandated production quotas in Alberta and the completion of a planned turnaround on Plant 1A. The turnaround on Plant 1B is scheduled for the second quarter of 2020.

Western Canada

Northern Operations

The Company’s Northern operations are located primarily in northwest Alberta. Production in 2019 consisted of approximately 1,300 bbls/day of light crude oil, 6,600 bbls/day of NGL and 172.8 mmcf/day of conventional natural gas. The area is heavily weighted towards conventional natural gas production (approximately 79%). Primary areas of operation include Edson and Grande Prairie, where operations are centered on liquids-rich gas resources.

Edson operations are located primarily in west-central Alberta and consist of the Ansell and Galloway areas. The Ansell conventional natural gas resource play is located in the deep basin Cretaceous formation, with the Company holding an average 95% working interest in approximately 177 net sections of contiguous lands. The Company has been actively developing the Spirit River formation since 2012 using multi-stage fractured horizontal wells. Production from the Ansell and Galloway areas has doubled since 2012 and in 2019 averaged 2,200 bbls/day of NGL and 112.6 mmcf/day of conventional natural gas. In 2019, the Company drilled two wells and completed six wells, while also participating in one non-operated well. In November 2019, the Company consolidated the majority of its Ansell production to the new HMGP Corser gas plant and shut-in some older area facilities to reduce costs.

Grande Prairie operations are located primarily in northwest Alberta and consist primarily of the Wembley, Kakwa, Wapiti and Karr areas. Production from Grande Prairie in 2019 averaged 1,300 bbls/day of light crude oil, 4,400 bbls/day of NGL and 60.2 mmcf/day of conventional natural gas. A drilling program targeting the oil and liquids-rich conventional natural gas Montney formation in the Wembley and Karr areas continued with five wells drilled in 2019 and nine wells completed. Six of these wells were brought on production in the fourth quarter of 2019, averaging 500 boe/day in 2019, with the remaining two beginning production in early 2020. At Wembley, the Company has a processing agreement at the Tidewater Pipestone Gas Plant and a transportation agreement with HMGP for a pipeline connection between the Company’s 13-26 pad and the Tidewater take point. The Kakwa Spirit River liquids-rich conventional natural gas resource play averaged 50 bbls/day of light crude oil, 2,600 bbls/day of NGL and 41.0 mmcf/day of conventional natural gas in 2019. During the year, the Company drilled three wells and completed six wells in Kakwa. Development is focused on the Cardium oil play in the Wapiti area south of the city of Grand Prairie, Alberta, utilizing horizontal drilling and multi-stage fracturing technology to unlock crude oil reserves. During 2019, production from the Cardium play averaged 2,400 boe/day.

Southern Operations

The Company’s Southern operations are primarily located in central and southern Alberta. As at December 31, 2019, the Company operated one crude oil and four conventional natural gas facilities with approximately 600 active wells throughout the area. Production in 2019 averaged 1,100 bbls/day of light crude oil, 2,100 bbls/day of NGL and 36.0 mmcf/day of conventional natural gas. In September 2019, the Company signed a Purchase and Sale Agreement to divest the assets in the Hussar area. In 2019, production from these assets averaged 300 bbls/day of light crude oil, 250 bbls/day of NGL and 7.5 mmcf/day of conventional natural gas. The sale was completed on February 11, 2020.

In 2019, the Company continued to participate in an eight-well non-operated Viking program in the North Blackstone area. During the year, four wells were drilled and eight wells were completed and brought on production by the end of 2019. During 2019, production from this program averaged 1,400 boe/day.

Rainbow Lake Development

Rainbow Lake, located approximately 900 kilometres northwest of Edmonton, Alberta, is the site of the Company’s largest light crude oil production operation in Western Canada. Production during 2019 from the Rainbow Lake assets averaged 4,700 bbls/day of light crude oil, 4,000 bbls/day of NGL and 72.9 mmcf/day of conventional natural gas. The Company continued a Muskeg oil appraisal program in 2019 with one well drilled and 11 wells completed during the year. During the year, the Company successfully completed a 21-day turnaround at the Rainbow Lake facility, on time and without any safety incidents.

The Company holds a 50% 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.

 

Husky Energy Inc. | Annual Information Form 2019 | 12

Northwest Territories

The Company acquired two ELs in 2011 in the Northwest Territories at the Slater River Canol shale play, which were consolidated as one EL in 2015 and cover 483,000 gross acres (466,000 net acres). Two pilot wells were drilled and suspended in 2012 which satisfied the requirements to extend the term of both the ELs to their full nine-year term. In 2016, the Company was awarded a Significant Discovery Declaration on 545 sections (150,000 hectares) of land within the ELs north of the Gambill Fault, and granted separately a Significant Discovery License over five sections of land south of the Gambill Fault. Abandonment work on the two pilot wells and 12 water monitoring wells in addition to reclamation of well sites and surplus infrastructure commenced in the fourth quarter of 2018 and carried through the 2019 winter season. In addition, summer work in 2019 included continued reclamation work as well as maintenance on the existing infrastructure that will remain in place to service the Significant Discovery Declaration area.

Infrastructure and Marketing

Overview

The Company is engaged in the marketing of both its own and other producers’ crude oil, natural gas, NGL, asphalt, sulphur and petroleum coke production. The sale and transportation of the Company’s production and third-party commodity trading volumes are managed 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 production and/or third-party commodity trading volumes from Canada to the U.S. market.

Husky Midstream Limited Partnership

HMLP was created in July 2016 with the sale of selected pipeline gathering systems in Alberta and Saskatchewan and the Lloydminster and Hardisty terminals. CKI Infrastructure Holdings Limited owns 16.25%, Power Assets Holdings Limited owns 48.75% and Husky owns 35% of HMLP and is the operator. HMLP has approximately 2,200 kilometres of pipeline in the Lloydminster region, 4.1 million barrels of storage capacity at Hardisty and Lloydminster and other ancillary assets. The Lloydminster Terminal, with a total storage capacity of 1.0 million barrels, serves as a hub for the gathering systems. The pipeline system transports blended heavy crude oil to Lloydminster, providing feedstock for the Upgrader and for the Asphalt Refinery, and to Hardisty where the system connects to downstream pipelines accessing markets across Canada and the United States. Blended heavy crude oil and bitumen 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 3.4 million barrels, acts as the exclusive blending hub for Western Canada Select (“WCS”), the largest heavy oil benchmark pricing point in North America.

HMLP has a separate Board of Directors from Husky and independent financing that supports both significant growth projects that are under construction and planned future expansions. Approximately $700 million in growth projects are underway. HMLP is in the process of diversifying its operations beyond the Lloydminster and Hardisty area and has completed construction of the Ansell Corser Gas Plant, which added 120 mmcf/day of processing capacity in the fourth quarter of 2019.

A major pipeline project is underway in Saskatchewan to provide transportation for the anticipated increase in the Company’s bitumen production. The Hardisty terminal is also expanding to provide additional pipeline connectivity and crude oil storage for customers. The assets will play an integral and valuable role in the successful transportation of heavy oil and bitumen production to end markets by providing connections to the Upgrader and to the 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 U.S. Midwest. This strategy was further supported through the acquisition of the Lima Refinery in 2007, which enabled the Company’s Canadian synthetic and bitumen production, along with additional third-party crude and other feedstocks, 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 Keystone pipeline commitment, the Lima Refinery is able to access a significant amount of Canadian crude oil as part of its crude feedstock requirements. The Keystone pipeline has enabled the Company to transport crude oil through interconnecting pipeline systems to the Lima Refinery and/or sell it into the Cushing, Oklahoma market.

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 mitigated these effects through the reliability of its proprietary pipeline system, its firm capacity on export pipelines and its demand for Canadian crude oil feedstock for its Canadian upgrading and refining assets. In 2017, the Company further enhanced this integration when it purchased the 50,000 barrel-per-day Superior Refinery, which runs a combination of heavy Canadian crude and light crudes from Canada and the U.S. The Superior Refinery is located on the Enbridge Mainline crude system. As a seller and buyer of crude oils, the Company has a relatively balanced exposure to many location and grade differentials.

 

Husky Energy Inc. | Annual Information Form 2019 | 13

The Company has been 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 via trucks to rail-loading facilities, where netbacks can be increased relative to pipeline alternatives. While the Company’s primary focus is on low-cost pipeline transportation options, it has maintained the flexibility to access crude by rail markets.

In December of 2018, the Government of Alberta imposed an oil production curtailment order in Alberta. This reduced the economic motivation to export crude by rail or develop longer term market access strategies.

Natural Gas Storage Facilities

The Company has operated a 25 bcf natural gas storage facility at Hussar, Alberta since 2000.

Commodity Marketing

The Company has developed its commodity marketing operations to include the acquisition of third-party volumes to enhance the value of its Integrated Corridor assets.

Currently, 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 Upgrader and its Ohio and Wisconsin refineries. The Company supplies feedstock to the Upgrader and to the 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, upgrading and marketing operations. The Company markets light and medium crude oil and NGL sourced from its own production and third-party production. Light crude oil is acquired for processing by the Lima Refinery and the Superior Refinery. The Company supplies a portion of the synthetic crude oil produced at the Upgrader to the Lima Refinery and Superior Refinery, and markets the rest to refiners in Canada and the 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 Company trades natural gas to generate revenue from managed assets, including transportation and natural gas storage facilities.

Upgrading Operations

The Company owns and operates the Upgrader. The Upgrader is designed to process blended heavy crude oil feedstock, creating high quality, low sulphur synthetic crude oil and ultra-low sulphur diesel and recover diluent from the feedstock for return to and reuse in the field. Synthetic crude oil is used as refinery feedstock for the production of transportation fuels in Canada and the U.S.

The Upgrader was commissioned in 1992 with an original design capacity of 46,000 bbls/day of synthetic crude oil. In 2007, the Upgrader commenced production of transportation grade diesel. The Upgrader’s current rated production capacity is 80,000 bbls/day of synthetic crude oil, diluent and ultra low sulphur diesel.

Production at the Upgrader in 2019 averaged 54,930 bbls/day of synthetic crude oil, 13,880 bbls/day of diluent and 6,100 bbls/day of ultra low sulphur diesel. In addition, as by-products of its upgrading operations, the Upgrader produced approximately 339 long ton/day of sulphur and 961 long ton/day of petroleum coke during 2019. These products are sold in Canadian and international markets.

Canadian Refined Products

The Company’s Canadian refined products operations include manufacturing of fuel and fuel grade ethanol, manufacturing of asphalt products from heavy crude oil and bitumen 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.

Until its sale by the Company in November 2019, light oil was processed and refined products were produced at the Prince George Refinery and such products were also acquired from third-party refiners and marketed through the Company’s retail and commercial petroleum outlets and through direct marketing to third-party dealers and end users. On November 1, 2019, the Prince George Refinery was sold to Tidewater and in conjunction with the deal, Husky agreed to a five-year offtake agreement to purchase the refined products at market price. Asphalt and residual products are produced at the Asphalt Refinery and are marketed directly or through the Company’s eight terminals located in Western Canada and the U.S. Midwest.

 

Husky Energy Inc. | Annual Information Form 2019 | 14

Asphalt Refinery

The Asphalt Refinery processes heavy crude oil and bitumen into asphalt products used in road construction and maintenance. The refinery has a throughput capacity of 30,000 bbls/day of heavy crude oil and bitumen. 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. The distillate stream is transferred to the Upgrader and treated for blending into the Husky Synthetic Blend (“HSB”) stream. Residuals are a blend of medium and light distillate and gas oil streams, which are typically sold directly to customers as refinery feedstock or drilling and well-fracturing fluids, or used in asphalt cutbacks and emulsions.

Refinery throughput averaged 26,400 bbls/day of blended heavy crude oil and bitumen feedstock during 2019. Due to the seasonal demand for asphalt products, many 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 that are outside of the normal paving season, such as increasing storage capacity and developing U.S. markets for asphalt products. This allows the Asphalt Refinery to run at or near full capacity throughout the year.

Asphalt Distribution Network

In addition to sales directly from the Asphalt Refinery, the Company, through the Husky Asphalt division, has an asphalt distribution network which consists of seven asphalt terminals located at: Kamloops, British Columbia; Edmonton and Lethbridge, Alberta; Yorkton, Saskatchewan; Winnipeg, Manitoba; Rhinelander, Wisconsin; and Crookston, Minnesota, and an emulsion plant located at Saskatoon, Saskatchewan. The Company also markets asphalt from independently operated terminals in the states of Washington, Minnesota, Wisconsin and Ohio.

Ethanol Plants

In September 2006, the Company commissioned an ethanol plant in Lloydminster, Saskatchewan. The plant has an annual nameplate capacity of 130 million litres. In December 2007, the Minnedosa, Manitoba ethanol plant was commissioned with an annual nameplate capacity of 130 million litres and both plants are currently operating above that capacity due to efforts to optimize yield. In 2019, ethanol production averaged 823 thousand litres/day.

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 and ethanol produced at the plant has a low carbon intensity designation.

Other Supply Arrangements

During 2019, the Company purchased approximately 27,250 bbls/day of refined petroleum products of which 25,850 bbls/day were pursuant to an agreement with Imperial Oil. The Company also acquired approximately 7,600 bbls/day of refined petroleum products pursuant to exchange agreements with third-party refiners in addition to Imperial Oil.

Retail and Commercial Network

During 2015, the Company and Imperial Oil entered into an agreement to create a single truck transport network of approximately 160 cardlock sites. The agreement has been fully implemented, and the consolidation of the two cardlock networks, under the Esso brand, was completed in the third quarter of 2017.

On January 8, 2019, the Company announced its intention to market and potentially sell its Canadian Retail and Commercial Fuels Network. The strategic review continues to progress.

As of December 31, 2019, there were 552 independently operated Husky and Esso-branded petroleum product outlets. These outlets include travel centres, convenience stores and cardlock and bulk distribution facilities located coast-to-coast. The Company’s network of travel centres features a proprietary cardlock system that enables commercial customers to make purchases using a fuel payment card that processes transactions, provides detailed billing and offers purchase controls and spending limits, as well as advanced fraud protection. A variety of full and self-serve retail stations serve urban and rural markets across the country, while the Company’s bulk distributors offer direct sales to commercial and agricultural markets in the Prairie provinces.

The Company’s retail and commercial operating model is balanced by corporate-owned/dealer-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 and proprietary and co-branded quick-serve restaurants. In addition to ethanol-blended gasoline, the Company sells diesel, propane and Mobil-branded 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.

 

Husky Energy Inc. | Annual Information Form 2019 | 15

The following table shows the number of Husky and Esso-branded petroleum outlets by province as of December 31, 2019:

 

		British Columbia				Alberta				Saskatchewan				Manitoba				Ontario				Quebec				New Brunswick				2019 Total				2018 Total
Husky-Branded Petroleum Outlets
Retail Owned Outlets			36				43				7				12				54				—				—				152				165
Leased			31				27				3				7				23				—				—				91				97
Independent Retailers			46				60				12				3				13				—				—				134				136
Total			113				130				22				22				90				—				—				377				398
Esso-Branded Petroleum Outlets
Retail Owned Outlets			18				18				4				4				15				—				—				59				48
Leased			3				4				—				3				3				—				—				13				8
Independent Retailers			33				23				4				6				30				6				1				103				100
Total			54				45				8				13				48				6				1				175				156
Cardlocks(1)			49				45				9				11				42				7				1				164				162
Convenience Stores(1)			80				83				13				21				94				—				—				291				296
Restaurants			8				9				3				1				13				—				—				34				34

 

(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 Canada.

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

 

		Years ended December 31,
Average Daily Sales Volume (mbbls/day)		2019				2018				2017
Gasoline			20.5				21.7				22.3
Diesel fuel			25.7				26.5				22.8
Liquefied Petroleum Gas			0.5				0.2				0.2
			46.7				48.4				45.3

 

Husky Energy Inc. | Annual Information Form 2019 | 16

U.S. Refining and Marketing

Lima Refinery

The Lima Refinery has a crude oil throughput capacity, depending on crude slate, of 175,000 bbls/day. The Lima Refinery, prior to the completion of the crude oil flexibility project, processed both light sweet crude oil and a small percentage of heavy crude oil feedstock sourced from the U.S. and Canada, which includes Canadian synthetic crude oil, including HSB produced by the 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 and Energy Transfer Partners pipeline systems and by rail car to primary markets in Ohio, Illinois, Indiana, Pennsylvania and southern Michigan.

During 2019, total production throughput at the Lima Refinery averaged 176,000 bbls/day excluding days for the 2019 shutdown. Production, excluding days for the crude oil flexibility project shutdown, consisted of an average of 85,000 bbls/day of gasoline, 72,000 bbls/day of distillates and 19,000 bbls/day of other products.

In 2016, the Company completed the first stage of the crude oil flexibility project to enable the refinery to process up to 10,000 bbls/day of heavy crude oil feedstock. The refinery completed a planned turnaround in the fourth quarter of 2019 and made final tie-ins for the project. The refinery is now designed to allow for the processing of up to 40,000 bbls/day of heavy crude oil from Western Canada and the ability to swing between light and heavy crude oil feedstock. The project was completed in early 2020 and the refinery will ramp up to full rates during the first quarter of 2020.

BP-Husky Toledo Refinery

The BP-Husky Toledo Refinery has a nameplate capacity of 160,000 bbls/day. Products from the refinery include low sulphur gasoline, ultra-low sulphur diesel, aviation fuels and by-products.

A feedstock optimization project completed during the 2016 turnaround improved the BP-Husky Toledo Refinery’s ability to process high-TAN crude oil to support production from the Sunrise Energy Project. Since January 1, 2017, the Company has been marketing its share of the joint operation’s refined product.

During 2019, the Company’s share of total throughput averaged 63,100 bbls/day, with the Company’s share of sales of gasoline averaging 39,000 bbls/day, distillates averaging 18,700 bbls/day and other fuel and feedstock averaging 7,100 bbls/day.

Superior Refinery

On November 8, 2017, the Company completed the acquisition of the Superior Refinery, which has a permitted throughput capacity of 50,000 bbls/day and an operating capacity of 45,000 bbls/day on its current crude slate. The refinery produces motor fuel products and asphalt from light and heavy crude oil originating from North Dakota and Western Canada.

The refinery also has associated infrastructure including five storage and distribution terminals that are strategically located throughout the northern area of the United States. These terminals include: the Superior products terminal; the Duluth Terminal in Duluth, Minnesota, which has a storage capacity of 200,000 barrels; the Duluth Marine Terminal in Duluth, Minnesota which has a storage capacity of 14,000 barrels; the Rhinelander Terminal in Rhinelander, Wisconsin, which has a storage capacity of 166,000 barrels; and the Crookston Terminal in Crookston, Minnesota, which has a storage capacity of 156,000 barrels.

On April 26, 2018, the Superior Refinery experienced an incident while preparing for a major turnaround and was taken out of operation. During 2019, demolition, site preparation work and permitting were completed, and the rebuild work commenced. The investment in the rebuild is estimated to be approximately US$750 million, of which the Company anticipates a substantial portion will be recovered from property damage insurance. This represents a change from the previous estimate of greater than US$400 million, with the change being due to a more complete assessment of the extent of equipment damage from the April 26, 2018 incident. The Company anticipates that lost income through April 2020 will be compensated by business interruption insurance. The refinery is being rebuilt with the same configuration and with the capability to run continuously at the 45,000 barrel-per-day operating capacity and will be able to produce a full slate of products, including asphalt, gasoline and diesel. Full operations are expected to resume in 2021.

 

Husky Energy Inc. | Annual Information Form 2019 | 17

Offshore

Asia Pacific

China

Liwan Gas Project

The Liwan Gas Project includes the conventional 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% working interest in the Liwan 3-1 and Liuhua 34-2 fields and a 75% working interest in the Liuhua 29-1 field, and China National Offshore Oil Corporation Limited (“CNOOC”) has 51% and 25% working interests, respectively. The initial development of the Liwan 3-1 and Liuhua 34-2 fields was separated into deepwater and shallow water development projects, with the Company acting as deepwater operator and CNOOC acting as shallow water operator. The deepwater 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, which has liquids separation facilities, 10 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. The single production well in the Liuhua 34-2 field was tied into the deepwater facilities of the Liwan 3-1 field and commenced production in December 2014.

In 2019, total conventional natural gas sales from Liwan 3-1 and Liuhua 34-2 averaged 311 mmcf/day and 38 mmcf/day, respectively. In 2019, the Company’s working interest share of production from the two fields was 171 mmcf/day of conventional natural gas and 7,400 bbls/day of NGL.

Substantial construction work was completed in 2019 at Liuhua 29-1 development project, the third deepwater gas field of the Liwan Gas Project. During the year, the remaining three wells were drilled, and all seven wells in the full field development were fully completed. The production pipeline and the mono-ethylene glycol supply line were engineered, fabricated and installed. The project is now approximately 80% complete, and construction activities will resume again in March 2020. First gas production from the Liuhua 29-1 field is expected by the end of 2020, with target production of 45 mmcf/day conventional natural gas (Husky working interest) and 1,800 bbls/day NGL (Husky working interest) when fully ramped up.

Block 15/33

The Company executed a PSC in December 2015 for an exploration block offshore China. Block 15/33 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 to 100 metres. The Company is the operator of the block during the exploration phase, with a working interest of 100%. In the event of a commercial discovery, its partner CNOOC may assume a working interest of up to 51% during the development and production phase. Under the PSC, the corresponding CNOOC share of exploration costs is to be recovered from production allocated to the Company.

The Company is progressing commercial development plans following the successful drilling and testing of the XJ34-3-2 exploration well. The block boundaries have been expanded and additional exploration and appraisal drilling is planned in 2020.

Block 16/25

The Company executed a PSC in April 2017 for an exploration block offshore China. Block 16/25 is located in the Pearl River Mouth Basin in the South China Sea, about 150 kilometres southeast of the Hong Kong Special Administrative Region and approximately 72 kilometres northeast of Block 15/33. The block covers an area of 44 square kilometres in water depths of approximately 85 to100 metres.

The Company drilled one exploration well in the third quarter of 2018, which encountered non-commercial hydrocarbons. This block was released and the costs written off in 2019 after technical evaluations were completed.

Blocks 22/11 and 23/07

The Company and CNOOC signed two PSCs for Blocks 22/11 and 23/07 in the Beibu Gulf area of the South China Sea in the first half of 2018. The Company is the operator of both blocks with a working interest of 100% during the exploration phase. In the event of a commercial discovery, its partner CNOOC may assume a participating partnership interest of up to 51% in either or both blocks for the development and production phases. The Company has elected to move into the second exploratory phase for Block 23/07.

 

Husky Energy Inc. | Annual Information Form 2019 | 18

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% working interest during exploration, while CPC Corporation has the right to participate in the development program up to a 50% interest.

The acquisition of 2-D seismic survey data was completed in 2014, and the acquisition of 3-D seismic survey data was completed in 2017. The Company is analyzing the 3-D seismic survey data to identify potential drilling prospects.

Indonesia

Madura Strait

The Company has a 40% interest in approximately 622,000 acres (2,516 square kilometres) of the Madura Strait, located offshore East Java, in Indonesia. The Company’s two partners are CNOOC, which is the operator and has a 40% working interest, and Samudra Energy Ltd., which holds the remaining 20% interest through its affiliate, SMS Development Ltd. The Madura Strait includes the operating BD field and developments at the MDA, MBH, MDK and MAC fields and three additional discoveries.

In 2019, total BD field sales averaged 82 mmcf/day of conventional natural gas and 6,100 bbls/day of NGL. The Company’s working interest share of production was 32 mmcf/day of conventional natural gas and 2,500 bbls/day of NGL.

At the MDA and MBH fields, the two shallow water platforms have been fully installed. Five MDA and two MBH field production wells are expected to be drilled in the 2020 timeframe pending regulatory approval. Contracting for a floating production unit to process the gas is also planned to be finalized during 2020 with fabrication to take place in 2021/2022. Gas production and sales are planned to commence in 2021 with gas sales under government-approved contracts into the East Java gas market. Subsequently, an additional shallow water field, MDK, is scheduled to be developed and tied into the MDA and MBH infrastructure. Pre-engineering activities and approvals progressed at the MAC field, where an approved Plan of Development is in place.

Anugerah

The Company executed a PSC in February 2014 with the Government of Indonesia for the Anugerah contract area. The Company holds a 100% interest in the Anugerah Block, which is located in the East Java Basin approximately 150 kilometres east of the Madura Strait. The block covers an area of 1,420,000 net acres (8,215 square kilometres).

The Company previously acquired 2-D and 3-D seismic survey data on the contract area, which was required during the first three years of the PSC. An analysis of those data and data from offset block information indicates that exploratory drilling would not be economic. The block will be relinquished in February 2020.

Atlantic

Overview

The Company’s Atlantic exploration and development program is focused in the Jeanne d’Arc Basin and the Flemish Pass Basin. The Jeanne d’Arc Basin contains the Hibernia, Terra Nova and Hebron fields, as well as the White Rose field and satellite extensions, including North Amethyst, West White Rose and South White Rose. In the Flemish Pass Basin, the Company holds a 35% 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 NL.

White Rose Field and Satellite Extensions

The White Rose field is located 354 kilometres off the coast of NL and is approximately 48 kilometres east of the Hibernia 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% working interest in the main field and a 68.875% working interest in the satellite extensions. To date, production has been facilitated via subsea tie-ins with wells drilled independently through drill centres and connected via flowlines to the SeaRose FPSO.

First oil was achieved at White Rose in November 2005. The White Rose field currently has 13 production wells, 10 water injection wells and three gas injection wells. Two infill production wells were completed during 2019. The Company’s share of light crude oil production from the White Rose field was 7,200 bbls/day (Husky working interest) during 2019.

On May 31, 2010, first oil was achieved from North Amethyst, the first satellite extension at 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. In September 2016, the Company began production from the deeper Hibernia formation at North Amethyst utilizing existing infrastructure. As of December 31, 2019, the field had eight production wells and four water injection wells. During 2019, light crude oil production from North Amethyst was 1,900 bbls/day (Husky working interest).

 

Husky Energy Inc. | Annual Information Form 2019 | 19

Initial production from West White Rose was achieved in September 2011 through a two-well pilot project. The pilot wells have helped provide further information on the reservoir to refine development plans for the full West White Rose field. During 2019, light crude oil production from this satellite field was 500 bbls/day (Husky working interest).

Production commenced from the South White Rose Extension in 2015 with production wells supported by both gas flood and water injection. As at December 31, 2019, the project had three production wells, one water injection well and one gas injection well. During 2019, light crude oil production from the South White Rose Extension was 2,700 bbls/day (Husky working interest).

In May 2017, the Company and its co-venturers announced plans to proceed with full field development at West White Rose using a fixed drilling platform. First oil is forecasted around the end of 2022, with the West White Rose Project expected to ramp up to peak production of 52,500 bbls/day (Husky working interest) in 2026 as development wells are brought online. Like the other White Rose tiebacks, the platform will leverage existing offshore infrastructure including the SeaRose FPSO. Construction of various components for the West White Rose platform is underway at sites in NL, and in Ingleside, Texas, where the facility’s topsides are being fabricated.

At the graving dock in Argentia, NL, four slipforms were completed on the outer caisson for the project’s concrete gravity structure and the first three interior decks were installed. The inner pedestal for the concrete structure will be slipformed to its full height during the 2020 construction season. Following a schedule review in early 2019, Husky and its partners decided to adjust the tow-out and installation date for the concrete gravity structure from 2021 to 2022. Project spending has been adjusted to meet the new schedule. As of December 31, 2019, the project was approximately 55% complete.

In late January 2019, the Company began a staged ramp-up of production at the White Rose field following a 250-cubic-metre oil spill from a failed flowline connector at the South White Rose Extension in November 2018. The flowline connector was replaced with one with a higher tensile strength and processes were updated to prevent a recurrence. All sections of the field were back in operation during August 2019. Husky’s investigation revealed that hydrate formation caused the flowline connector to separate. The C-NLOPB, which regulates the industry offshore NL, continues its investigation.

Terra Nova Field

The Terra Nova field is located approximately 350 kilometres southeast of St. John’s, NL. 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 has a 13% working interest in the field.

On December 20, 2019, production operations on the Terra Nova FPSO were safely shut-in in response to a C-NLOPB order citing insufficient redundancy of fire water pumps.

As at December 31, 2019, there were 15 development wells drilled in the Graben area, consisting of nine production wells, four water injection wells and two gas injection wells. In the East Flank area, there were 12 development wells, consisting of eight production wells and four water injection wells. The Far East has one extended reach production well and an extended reach water injection well. The operator continues to progress delineation and development opportunities at Terra Nova.

Light crude oil production during 2019 from the Terra Nova field was 4,100 bbls/day (Husky working interest).

East Coast Exploration

The Company holds working interests ranging from 5.8% to 100% in 23 Significant Discovery Areas in the Jeanne d’Arc Basin and Flemish Pass Basin, offshore NL and Baffin Island.

The Tiger’s Eye D-17 exploration well, drilled approximately 10 kilometres south of the White Rose field during the second quarter of 2019, did not encounter commercial quantities of hydrocarbons and has been expensed.

The Company continues to evaluate previous hydrocarbon discoveries at the White Rose A-24 exploration well, north of the SeaRose FPSO, and the Northwest White Rose A-78 well.

The Company and its partner continue to assess potential development of Bay du Nord and other discoveries in the Flemish Pass Basin. A benefits framework agreement was reached with the Government of NL in July 2018, based on an FPSO-based development concept to produce resources at Bay du Nord and Bay de Verde. Technological and commercial evaluations continue. The Company holds a 35% non-operated working interest in the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries.

The Company was awarded a parcel of land during the November 2019 C-NLOPB land sale. The EL is northwest of White Rose and adjacent to other Husky land holdings.

 

Husky Energy Inc. | Annual Information Form 2019 | 20

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Disclosure of Oil and Gas Activities

Operating Netback Analysis⁽¹⁾

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

 

		Year Ended				Three Months Ended
Average Per Unit Amounts		Dec 31, 2019				Dec 31, 2019				Sept 30, 2019				June 30, 2019				Mar 31, 2019
Company Total(2)
Sales volume (mboe/day)			290.0				311.3				294.8				268.4				285.2
Gross Revenue ($/boe)(3)		$	48.37			$	46.06			$	47.54			$	53.35			$	47.20
Royalties ($/boe)		$	3.29			$	3.25			$	3.21			$	3.69			$	3.03
Production and Operating Costs ($/boe)(3)		$	15.53			$	15.25			$	14.83			$	15.83			$	16.30
Transportation Costs ($/boe)(4)		$	0.16			$	0.08			$	0.19			$	0.22			$	0.18
Operating netback ($/boe)		$	29.39			$	27.48			$	29.31			$	33.61			$	27.69
Light and Medium Crude Oil ($/bbl)
Canada - Western Canada
Gross Revenue(3)		$	47.11			$	36.50			$	44.07			$	52.32			$	56.94
Royalties		$	9.10			$	10.24			$	9.90			$	9.65			$	6.73
Production and Operating Costs(3)		$	26.43			$	22.30			$	16.68			$	36.63			$	28.07
Operating netback		$	11.58			$	3.96			$	17.48			$	6.04			$	22.14
Canada - Atlantic Canada
Gross Revenue		$	86.44			$	84.54			$	83.47			$	92.00			$	92.12
Royalties		$	8.15			$	7.17			$	6.96			$	11.07			$	10.06
Production and Operating Costs		$	42.20			$	30.48			$	32.21			$	52.75			$	92.01
Transportation Costs(4)		$	2.89			$	0.97			$	2.66			$	4.74			$	6.87
Operating netback		$	33.20			$	45.92			$	41.64			$	23.44			($	16.82	)
Canada - Total
Gross Revenue(3)		$	72.85			$	71.67			$	71.32			$	77.07			$	73.09
Royalties		$	8.50			$	7.99			$	7.87			$	10.53			$	8.26
Production and Operating Costs(3)		$	36.85			$	28.29			$	27.42			$	46.66			$	57.52
Transportation Costs(4)		$	1.90			$	0.71			$	1.84			$	2.95			$	3.16
Operating netback		$	25.60			$	34.67			$	34.19			$	16.92			$	4.14
Heavy Crude Oil ($/bbl)
Canada - Total
Gross Revenue(3)		$	54.70			$	50.01			$	56.72			$	63.15			$	49.38
Royalties		$	5.08			$	4.27			$	5.26			$	5.86			$	4.99
Production and Operating Costs(3)		$	34.84			$	35.97			$	37.63			$	32.31			$	35.85
Operating netback		$	14.78			$	9.77			$	13.83			$	24.98			$	8.54
Bitumen ($/bbl)
Canada - Total
Gross Revenue(3)(4)		$	49.00			$	41.39			$	51.09			$	58.32			$	46.64
Royalties		$	2.45			$	2.12			$	2.60			$	3.18			$	1.96
Production and Operating Costs(3)		$	12.73			$	12.58			$	12.15			$	12.39			$	13.79
Operating netback		$	33.82			$	26.69			$	36.34			$	42.75			$	30.89

 

Husky Energy Inc. | Annual Information Form 2019 | 21

		Year Ended				Three Months Ended
Average Per Unit Amounts		Dec 31, 2019				Dec 31, 2019				Sept 30, 2019				June 30, 2019				Mar 31, 2019
Conventional Natural Gas ($/mcf)
Canada - Total
Gross Revenue(3)(5)		$	1.72			$	2.29			$	0.95			$	1.20			$	2.46
Royalties(5)(6)		($	0.01	)		$	0.07			($	0.11	)		($	0.09	)		$	0.07
Production and Operating Costs(3)		$	1.68			$	1.71			$	1.39			$	1.91			$	1.60
Operating netback		$	0.05			$	0.51			($	0.33	)		($	0.63	)		$	0.80
China
Gross Revenue		$	14.02			$	14.31			$	13.28			$	14.05			$	14.35
Royalties		$	0.80			$	0.88			$	0.75			$	0.75			$	0.76
Production and Operating Costs		$	0.90			$	0.86			$	1.02			$	0.87			$	0.88
Operating netback		$	12.32			$	12.57			$	11.51			$	12.43			$	12.71
Indonesia(7)
Gross Revenue		$	9.87			$	9.85			$	9.82			$	9.94			$	9.88
Royalties		$	1.10			$	1.01			$	1.06			$	1.07			$	1.25
Production and Operating Costs		$	1.40			$	1.47			$	1.04			$	1.59			$	1.53
Operating netback		$	7.37			$	7.37			$	7.72			$	7.28			$	7.10
Total
Gross Revenue(3)		$	6.44			$	7.02			$	5.44			$	6.19			$	7.12
Royalties		$	0.33			$	0.41			$	0.24			$	0.28			$	0.40
Production and Operating Costs(3)		$	1.40			$	1.39			$	1.25			$	1.54			$	1.34
Operating netback		$	4.71			$	5.22			$	3.95			$	4.37			$	5.38
Natural Gas Liquids ($/bbl)
Canada - Total
Gross Revenue(3)		$	23.38			$	23.88			$	17.13			$	25.06			$	27.47
Royalties		$	3.44			$	3.36			$	2.26			$	3.01			$	4.93
Production and Operating Costs(3)		$	10.20			$	10.88			$	8.76			$	11.18			$	10.14
Operating netback		$	9.74			$	9.64			$	6.11			$	10.87			$	12.40
China
Gross Revenue		$	67.28			$	67.87			$	61.81			$	69.77			$	69.11
Royalties		$	3.82			$	3.93			$	3.47			$	3.92			$	3.90
Production and Operating Costs		$	5.43			$	5.16			$	6.10			$	5.25			$	5.27
Operating netback		$	58.03			$	58.78			$	52.24			$	60.60			$	59.94
Indonesia(7)
Gross Revenue		$	88.91			$	90.33			$	83.03			$	101.07			$	81.96
Royalties		$	13.75			$	14.31			$	12.95			$	15.32			$	12.61
Production and Operating Costs		$	8.39			$	8.82			$	6.22			$	9.52			$	9.19
Operating netback		$	66.77			$	67.20			$	63.86			$	76.23			$	60.16
Total
Gross Revenue(3)		$	44.99			$	45.72			$	38.39			$	50.22			$	46.07
Royalties		$	4.70			$	4.56			$	3.94			$	4.86			$	5.41
Production and Operating Costs(3)		$	8.43			$	8.62			$	7.66			$	8.91			$	8.52
Operating netback		$	31.86			$	32.54			$	26.80			$	36.45			$	32.14

 

(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 have been deducted from both 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 price received.

(5)	Includes sulphur sales revenues/royalties.

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

(7)	Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

 

Husky Energy Inc. | Annual Information Form 2019 | 22

Production History

 

		Year Ended				Three Months Ended
Average Gross Daily Production		Dec 31, 2019				Dec 31, 2019				Sept 30, 2019				June 30, 2019				Mar 31, 2019
Canada - Western Canada
Light and Medium Crude Oil (mbbls/day)			8.5				8.9				9.4				7.4				8.9
Heavy Crude Oil (mbbls/day)			30.2				32.6				31.6				28.9				27.6
Bitumen (mbbls/day)			128.8				137.8				126.4				120.4				130.3
Conventional Natural Gas (mmcf/day)			297.5				297.7				310.4				279.6				301.8
NGL (mbbls/day)			12.7				12.6				13.0				10.7				14.4
Canada - Atlantic
Light and Medium Crude Oil (mbbls/day)			16.4				24.4				21.1				12.2				7.6
China - Asia Pacific(1)
Conventional Natural Gas (mmcf/day)			171.0				183.1				158.3				161.5				180.6
NGL (mbbls/day)			7.4				8.3				6.6				7.1				7.7
Indonesia - Asia Pacific(2)
Conventional Natural Gas (mmcf/day)			32.4				26.6				34.6				34.0				34.4
NGL (mbbls/day)			2.5				2.1				2.8				2.5				2.6
Total Gross Production (mboe/day)			290.0				311.3				294.8				268.4				285.2

 

(1)	Reported production volumes include Husky’s working interest production from the Liwan Gas Project (49%).

(2)	Reported production volumes include Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

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

 

		Oil Wells								Conventional Natural Gas Wells								Total
Producing Wells		Gross				Net				Gross				Net				Gross				Net
Canada
Alberta			1,526				1,337				1,690				1,174				3,216				2,511
Saskatchewan			2,209				2,138				82				81				2,291				2,219
British Columbia			—				—				121				121				121				121
Newfoundland			22				6				—				—				22				6
			3,757				3,481				1,893				1,376				5,650				4,857
International
China			—				—				10				5				10				5
Indonesia			—				—				4				2				4				2
			—				—				14				7				14				7
As at December 31, 2019			3,757				3,481				1,907				1,383				5,664				4,864
		Oil Wells								Conventional Natural Gas Wells								Total
Non-Producing Wells		Gross				Net				Gross				Net				Gross				Net
Canada
Alberta			1,516				1,385				841				632				2,357				2,017
Saskatchewan			3,755				3,601				184				165				3,939				3,766
British Columbia			—				—				12				10				12				10
As at December 31, 2019			5,271				4,986				1,037				807				6,308				5,793

 

(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, 2019.

(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, 2019, the Company had a royalty interest in 832 wells, of which 452 were oil producers and 380 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 2019, there were 959 gross and 869 net oil wells and 75 gross and 63 net conventional natural gas wells that were completed in two or more formations and from which production is not commingled.

 

Husky Energy Inc. | Annual Information Form 2019 | 23