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2007
United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 40-F
o | Registration Statement pursuant to section 12 of the Securities Exchange Act of 1934 |
þ | Annual report pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2007 | Commission File Number: 001-04307 |
Husky Energy Inc.
(Exact name of Registrant as specified in its charter)
Alberta, Canada (Province or other jurisdiction of incorporation or organization) | 1311 (Primary Standard Industrial Classification Code Numbers) | Not Applicable (I.R.S. Employer Identification Number (if applicable)) |
707-8th Avenue S.W., P.O. Box 6525 Station D, Calgary, Alberta, Canada T2P 3G7
(403) 298-6111
(Address and telephone number of Registrant’s principal executive office)
(403) 298-6111
(Address and telephone number of Registrant’s principal executive office)
CT Corporation System, 111 Eighth Avenue, New York, New York 10011
(212) 894-8400
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)
(212) 894-8400
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of Each Class:None
Title of Each Class:None
Securities registered or to be registered pursuant to Section 12(g) of the Act:
Title of Each Class:None
Title of Each Class:None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
The Registrant is a “voluntary filer” and files annual reports onForm 40-F, amendments to such reports and furnishes
information onForm 6-K to the Securities and Exchange Commission, pursuant to its obligations under its Indentures
dated June 14, 2002 and September 11, 2007 relating to its debt securities issued thereunder.
For annual reports, indicate by check mark the information filed with this Form:
þ Annual information form | þ 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: 848,960,310
Common Shares outstanding as of December 31, 2007
Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant toRule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the filing number assigned to the Registrant in connection with such Rule.
Yes o | No þ |
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 þ | No o |
The Annual Report onForm 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: For F-9 FileNo. 333-137211.
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Principal Documents
The following documents have been filed as part of this Annual Report onForm 40-F:
A. | Annual Information Form |
The Annual Information Form of Husky Energy Inc. (“Husky” or “the Company”) for the year ended December 31, 2007 is included as Document A of this Annual Report onForm 40-F.
B. | Audited Annual Financial Statements |
Husky’s audited consolidated financial statements for the year ended December 31, 2007 and 2006, including the auditor’s report with respect thereto, is included as Document B of this Annual Report onForm 40-F. The reconciliation of Husky’s audited consolidated financial statements to accounting principles generally accepted in the United States is included as Document C of this Annual Report onForm 40-F. In addition, see the “Disclosure about Oil and Gas Producing Activities — Statement of Financial Accounting Standards No. 69” in the Annual Information Form included as Document A of this Annual Report onForm 40-F.
C. | Reconciliation to Accounting Principles Generally Accepted in the United States |
The reconciliation of Husky’s audited consolidated financial statements to accounting principles generally accepted in the United States is included as Document C of this Annual Report onForm 40-F. In addition, see the “Disclosure about Oil and Gas Producing Activities — Statement of Financial Accounting Standards No. 69” in the Annual Information Form as Document A of the Annual Report onForm 40-F.
D. | Management’s Discussion and Analysis |
Husky’s Management’s Discussion and Analysis for the year ended December 31, 2007 is included as Document D of this Annual Report onForm 40-F.
Certificates
See Exhibits 31.1 and 32.1, which are included as Exhibits to this Annual Report onForm 40-F.
Controls and Procedures
See the section “Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2007 which is included as Document D to this Annual Report onForm 40-F.
Management’s Annual Report on Internal Control Over Financial Reporting
Attestation of the Registered Public Accounting Firm
The required disclosure is included in “Auditors’ Report to the Shareholders” that accompanies Husky’s consolidated financial statements for the year ended December 31, 2007, which is included as Document B to this Annual Report onForm 40-F.
Change in Internal Control Over Financial Reporting
The required disclosure is included in the section “Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2007, which is included as Document D to this Annual Report onForm 40-F.
Notice Pursuant to Regulation BTR
Not Applicable.
Audit Committee Financial Expert
The Board of Directors of Husky has determined that R. Donald Fullerton is an “audit committee financial expert” (as defined in paragraph 8(b) of General Instruction B toForm 40-F) serving on its Audit Committee. Pursuant to paragraph 8(a) (2) of General Instruction B toForm 40-F, the Board has applied the definition of independence applicable to the audit committee members of New York Stock Exchange listed companies. Mr. Fullerton is a corporate director and is independent under the New York Stock Exchange standard. For a description of Mr. Fullerton’s relevant experience in financial matters, see Mr. Fullerton’s five year history in the section “Directors and Officers” in the Management
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Information Circular dated March 10, 2008 posted onwww.sedar.com and in the section “Audit Committee” in the Registrant’s Annual Information Form for the year ended December 31, 2007, which is included as Document A of this Annual Report onForm 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 all its other employees, and is posted on its website atwww.huskyenergy.ca. In the fiscal year ended December 31, 2007, there have been no amendments to Husky’s Code of Ethics, nor has Husky granted a waiver including an implicit waiver from a provision of its Code of Ethics. 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 toForm 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 toForm 40-F, |
Husky will promptly disclose such occurrences on its website following the date of such amendment or waiver 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.
Principal Accountant Fees and Services
See the section “Audit Committee” in the Annual Information Form for the year ended December 31, 2007, which is included as Document A to this Annual Report onForm 40-F.
Off-balance Sheet Arrangements
See the section “Off- balance Sheet Arrangements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2007, which is included as Document D to this Annual Report onForm 40-F.
Disclosure of Contractual Obligations
See the section “Contractual Obligations and Other Commercial Commitments” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2007, which is included as Document D to this Annual Report onForm 40-F.
Identification of the Audit Committee
Husky has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: R.D. Fullerton, M.J.G. Glynn and W. Shurniak.
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 registered pursuant toForm F-9; the securities in relation to which the obligation to file an annual report onForm 40-F arises; or transactions in said securities.
Consent to Service of Process
Form F-X signed by Husky and its agent for service of process has been filed with the Commission together withForms F-9 (333 - 137211), (333 - 117972) and (333 - 89714) in connection with its debt securities registered on such forms.
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 theForm F-X referencing the file number of Husky.
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SIGNATURES
Pursuant to the requirements of the Exchange Act, Husky Energy Inc. certifies that it meets all of the requirements for filing onForm 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereto duly authorized.
Dated this 10th day of March, 2008
Husky Energy Inc.
By: | /s/ John C.S. Lau |
Name: John C.S. Lau
Title: | President & Chief Executive Officer |
By: | /s/ James D. Girgulis |
Name: James D. Girgulis
Title: | Vice President, Legal & Corporate Secretary |
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Document A
Form 40-F
Form 40-F
ANNUAL INFORMATION FORM
For the Year Ended December 31, 2007
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Husky Energy Inc.
Annual Information Form
For the Year Ended December 31, 2007
March 10, 2008
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In this Annual Information Form the term “Husky,” “we,” “our,” “us,” and “the Company,” means Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis including information with respect to predecessor corporations.
Unless otherwise indicated, all financial information is in accordance with accounting principles generally accepted in Canada. Unless otherwise indicated, gross reserves or gross production are reserves or production attributable to Husky’s interest prior to deduction of royalties; net reserves or net production are reserves or production net of such royalties. Gross or net production reported refers to sales volume, unless otherwise indicated. Natural gas volumes are converted to a boe basis using the ratio of six mcf of natural gas to one bbl of oil and natural gas liquids. Unless otherwise indicated, oil and gas commodity prices are quoted after the effect of hedging gains and losses. Natural gas volumes are stated at the official temperature and pressure basis of the area in which the reserves are located. The calculation of barrels of oil equivalent (boe) and thousands of cubic feet equivalent (mcfge) are based on a conversion rate of six thousand cubic feet to one barrel of oil.
Boe or mcfge may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
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This Annual Information Form contains “forward-looking information and statements”
within the meaning of applicable securities laws. For a full discussion of the forward-looking
information and statements and the risks to which they are subject, see the
“Special Note Regarding Forward-Looking Statements”
on page 66 of this Annual Information Form.
within the meaning of applicable securities laws. For a full discussion of the forward-looking
information and statements and the risks to which they are subject, see the
“Special Note Regarding Forward-Looking Statements”
on page 66 of this Annual Information Form.
EXCHANGE RATE INFORMATION
Except where otherwise indicated, all dollar amounts stated in this Annual Information Form (“AIF”) are Canadian dollars. The following table discloses various indicators of the Canadian/United States rate of exchange or the cost of a U.S. dollar in Canadian currency for the three years indicated.
Year ended December 31 | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Year end | 0.988 | 1.165 | 1.166 | |||||||||
Low | 0.917 | 1.095 | 1.151 | |||||||||
High | 1.185 | 1.179 | 1.210 | |||||||||
Average | 1.074 | 1.134 | 1.211 |
Notes:
(1) | The exchange rates were as quoted by the Federal Reserve Bank of New York for the noon buying rate. |
(2) | The high, low and average rates were either quoted or calculated as of the last day of the relevant month. |
DISCLOSURE OF EXEMPTION UNDER NATIONAL INSTRUMENT51-101
Husky believes that comparability of its disclosures with those required in its major capital market, the United States, is important to many of the investors and prospective investors in its securities. Accordingly, we applied for and were granted an exemption by the Canadian securities regulators under the provisions of National Instrument51-101 “Standards of Disclosures for Oil and Gas Activities” (“NI51-101”). The exemption permits us to substitute disclosures required by and consistent with those of the Securities and Exchange Commission of the United States (“SEC”) and the Financial Accounting Standards Board in the United States (“FASB”) in place of much of the disclosure required byNI 51-101. In accordance with the exemption, proved oil and gas reserves data and certain other disclosures with respect to our oil and gas activities in this Annual Information Form are presented in accordance with the following requirements:
• | The FASB Statement No. 69 “Disclosure about Oil and Gas Producing Activities — an amendment of FASB Statements No.’s 19, 25, 33 and 39” (“FAS 69”); | |
• | FASB Current Text Section Oi5, “Oil and Gas Producing Activities” paragraphs .103, .106, .107, .108, .112, .160 through .167, .174 through .184 and .401 through .408; | |
• | SEC Industry Guide 2; | |
• | SEC Item 102 ofregulation S-K (17 CFR 229.102); | |
• | SEC Item 302(b) ofRegulation S-K (17 CFR 229.302(b)); and | |
• | The definitions and disclosures required by SECRegulation S-X (CFR 210.4-10). |
Proved oil and gas reserves information and other disclosures about oil and gas activities in this Annual Information Form following SEC requirements may differ from corresponding information otherwise required by NI51-101. Proved reserves disclosed in this Annual Information Form are in accordance with the SEC definitions.
NI51-101 specifies that proved reserves be determined in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”) definitions. There were no material differences between the oil and gas reserves determined using the SEC definitions and the COGEH definitions. In addition, NI51-101 requires the inclusion of probable reserves and their associated future net revenue. The SEC does not normally permit the disclosure of probable reserves in documents filed with them.
The SEC requires the evaluation of oil and gas reserves to be based on prices, costs, fiscal regimes and other economic and operating conditions in effect at the time the evaluation is made (“constant prices”). NI51-101 allows the evaluation of oil and gas reserves on this basis as supplemental disclosure but requires an evaluation of oil and gas reserves to be based on a forecast of economic conditions. In establishing the constant prices for bitumen NI51-101 provides for a
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different interpretation of the phrase “price will be the posted price of oil and the spot price of gas, after historical adjustments for transportation, gravity and other factors.” On January 20, 2005 the Canadian Securities Administrators issued Staff Notice51-315 Guidance Regarding the Determination of Constant Prices for Bitumen Reserves under National Instrument51-101“Standards of Disclosure for Oil and Gas Activities.”Bitumen is very heavy crude oil that is 10 degrees API and lower. This guidance stipulates that for establishing the constant prices for bitumen companies should use the posted price for WTI and apply the average annual adjustment for transportation, gravity and other factors that create the difference in price between WTI and bitumen. This method was developed primarily in response to the fluctuations in bitumen prices that, for various reasons, tend to experience the lowest prices at the end of the calendar year. Under the FASB/SEC rules the determination of constant price for bitumen does not permit the use of annual average differentials between WTI and bitumen. These rules require the differentials prevailing on the last day of the period to be used to calculate the constant price. There is no difference in determining the constant prices for crude oil classified as heavy oil, lighter than 10 degrees API under NI51-101 and FASB/SEC although heavy oil, which we classify as crude oil between 10 degrees and 20 degrees API, tends to behave in a similar manner as bitumen.
Husky believes that its reserves evaluators are qualified and that it has a well established reserves evaluation process that is at least as rigorous as would be the case were we to rely upon independent reserves evaluators. Husky has adopted written evaluation practices and procedures using the COGEH modified to the extent necessary to reflect the definitions and standards under SEC disclosure requirements. In addition, Husky engaged a firm of independent qualified reserves evaluators to conduct an audit of the reserves estimates and respective present worth value of the reserves as at December 31, 2007. They conducted their audit in accordance with the standards described in the COGEH and the auditing standards generally accepted in the United States.
The Audit Committee of the Board of Directors has reviewed our procedures for providing information to the internal and external qualified oil and gas reserves evaluators; met with the internal and , if applicable, external qualified oil and gas reserves evaluator(s) to determine whether any restrictions placed by management affect the ability of the qualified oil and gas reserves evaluator to report without reservation; and reviewed the reserves data with management and the internal qualified reserves evaluator. To assist the Audit Committee in its review, an external consultant was engaged to provide an assessment and recommendation in respect of the oil and gas reserves evaluation and reporting process.
NI51-101 prescribes a relatively comprehensive set of disclosures in respect of oil and gas reserves and other disclosures about oil and gas activities. In comparison, the SEC prescribes a minimum set of disclosures and advises reporting companies not to approach the SEC rules and regulations as merely a blank form but encourages them to provide such additional information that is necessary to further an investor’s understanding of their business.
In either jurisdiction, information to further an investor’s understanding is specifically encouraged to be included in Management’s Discussion and Analysis (“MD&A”). The MD&A is intended to be a narrative explanation describing the Company, both its history and prospects, as perceived by management. The readers of the AIF are encouraged to also read the Company’s MD&A, which is filed, in accordance with the requirements of the Canadian Securities Administrators, on the System for Electronic Data Analysis and Retrieval (“SEDAR”). Documents filed on SEDAR may be accessed online atwww.sedar.com. This AIF together with the MD&A and the Company’s Audited Consolidated Financial Statements are included in Husky’sForm 40-F which is filed with SEC’s Electronic Data Gathering Analysis and Retrieval (“EDGAR”) system, which may be accessed online atwww.sec.gov.
CORPORATE STRUCTURE
Husky Energy Inc.
Husky Energy Inc. (“Husky Energy”) was incorporated under theBusiness Corporations Act(Alberta) on June 21, 2000.
Husky Energy has its registered office and its head and principal office at 707 — 8th Avenue S.W., P.O. Box 6525, Station D, Calgary, Alberta, T2P 3G7.
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Intercorporate Relationships
The principal subsidiaries of Husky and place of incorporation, continuance or place of organization, as the case may be, are as follows. All of the following companies are 100% beneficially owned or controlled or directed, directly or indirectly.
Name | Jurisdiction | |
Subsidiaries of Husky Energy Inc. | ||
Husky Oil Operations Limited | Nova Scotia | |
Subsidiaries of Husky Oil Operations Limited | ||
Husky Oil Limited | Nova Scotia | |
Husky Energy Marketing Inc. | Alberta | |
Husky (U.S.A.) Inc. | Delaware | |
Husky Refining Company | Delaware | |
HOI Resources Co. | Nova Scotia | |
Canterra Resources Canada Ltd. (formerly 147212 Canada Ltd.) | Canada | |
Subsidiaries of Husky (U.S.A.) Inc. | ||
Husky Gas Marketing Inc. | Delaware | |
Subsidiaries of Husky Refining Company | ||
Lima Refining Company | Delaware | |
Husky Marketing and Supply Company | Delaware | |
Subsidiaries of HOI Resources Co. | ||
Husky Energy International Corporation | British Columbia | |
Subsidiaries of Husky Energy International Corporation | ||
Husky Oil China Ltd. | Alberta | |
Husky Oil (Madura) Ltd. | British Virgin Islands | |
Husky Oil Overseas Ltd. | Alberta |
GENERAL DEVELOPMENT OF HUSKY
Three Year History of Husky
2005
In September 2005, Husky announced that its Prince George refinery was capable of producing gasoline that meets the Government of Canada’s new environmental specifications thereby completing the first of two phases of a “Clean Fuel” refinery modification project.
On November 12, 2005, first oil was produced at the White Rose oilfield offshore Newfoundland and Labrador. Husky holds a 72.5% interest in White Rose. Production from White Rose is 31° API light crude oil and will supply markets both in Canada and the United States.
2006
In January 2006, Husky acquired two additional Exploration Licences (“EL”) in the Jeanne d’Arc Basin of the Grand Banks Region offshore Newfoundland and Labrador. Husky holds a 100% working interest in the 33,320 acre EL1094 and the 5,260 acre EL 1096. Husky has committed to spend a total of $37 million evaluating the prospects of these ELs.
On February 1, 2006, Husky redeemed its 8.45% senior secured bonds for U.S. $85 million.
In April 2006, Husky acquired 23,680 acres of oil sands leases adjacent to its Saleski oil sand property. The cost was $10 million and increased Husky’s holdings in the Saleski area to 178,560 acres.
In June 2006, Husky completed a farm-in agreement with Norsk Hydro to earn additional interests in two Significant Discovery Licences in the Jeanne d’Arc Basin. Under the terms of the agreement Husky drilled a delineation well on West Bonne Bay, Significant Discovery Licence 1040, to earn a 25% working interest and an additional 7.5% working interest in North Ben Nevis, Significant Discovery Licence 1008.
In July 2006, Husky acquired 14,560 acres of oil sands leases adjacent to its Saleski oil sand property. The cost was $6.6 million and increased Husky’s holdings in the Saleski area to 193,120 acres.
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The second phase of modifications to produce low sulphur diesel fuel at the Prince George refinery was completed during the second quarter of 2006. The refinery’s design rate capacity was increased to 12 mbbls/day as a result of this two phase modification.
In August 2006, Husky acquired 19,200 acres of oil sands leases adjacent to its Saleski oil sands property. The cost was $7.9 million and increased Husky’s holdings in the Saleski area to 212,320 acres.
In August 2006, Husky acquired three exploration blocks in the South China Sea totalling 4,168,915 acres. Block29/06 covers 2,289,431 acres in the Pearl River Mouth Basin in 500 to 1500 metres of water, block35/18 covers 1,104,314 acres in the Yinggehai Basin in less than 120 metres of water and block50/14 covers 775,170 acres in the Yinggehai Basin in less than 120 metres of water.
In September 2006, Husky commissioned its Lloydminster ethanol plant, which is located adjacent to Husky’s heavy oil upgrader on the Saskatchewan side of Lloydminster and has a design capacity to produce 130 million litres of ethanol per year.
In September 2006, Husky filed a base shelf prospectus that permits issue of up to U.S. $1 billion of debt securities or the equivalent in other currencies during the 25 months that the prospectus is in effect.
In September 2006, Husky acquired 26,880 acres of oil sands leases adjacent to its Saleski oil sands property. The cost was $13.7 million and increased Husky’s holdings in the Saleski area to 239,200 acres.
In September 2006, Husky acquired an exploration block in the North East Java Basin offshore Indonesia totalling 1.2 million acres. This increased Husky’s total holding in Indonesia to approximately 1.8 million acres.
In October 2006, Husky commissioned its Tucker oil sands project located 30 kilometres north-west of Cold Lake Alberta. The project employs a steam assisted gravity drainage recovery (“SAGD”) system with a plant that has a design rate capacity of 30 mbbls/day.
2007
On January 15, 2007, Husky acquired an interest in three ELs in the Jeanne d’Arc Basin offshore Newfoundland and Labrador. Husky acquired a 100% interest in EL 1099 covering 61,376 acres, a 50% interest in EL 1100 covering 75,545 acres and a 50% interest in EL 1101 covering 51,914 acres. Husky has committed to spend $23.5 million on these EL areas during the next five years.
On June 19, 2007, Husky announced it had been awarded two exploration and exploitation licences by the governments of Greenland and Denmark. The licences are for Block 5 with an area of 10,138 square kilometres and Block 7 with an area of 10,929 square kilometres. These blocks are located in an offshore area west of Disko Island in West Greenland. Husky holds an 87.5% interest. Both of these licences expire on May 31, 2017.
Effective July 1, 2007, Husky acquired all of the issued and outstanding shares of the Lima Refining Company from The Premcor Refinery Group Inc., a wholly owned subsidiary of Valero Energy Corporation. The purchase price was U.S. $1.9 billion plus U.S. $540 million for feedstock and product inventory. The 160 mbbls/day refinery is located at Lima, Ohio.
On September 6, 2007, Husky announced the issuance of U.S. $300 million of 6.2% 10 year notes due September 15, 2017 and U.S. $450 million of 6.8% 30 year notes due September 15, 2037. These notes rank equally with our other unsecured debt. The net proceeds from the notes were used to partially repay U.S. $1.5 billion short-term bridge financing arranged to acquire the Lima refinery.
On October 11, 2007, Husky was awarded an exploration and exploitation licence by the governments of Greenland and Denmark. The licence is for Block 6 with an area of 13,213 square kilometres. Block 6 is located in an offshore area west of Disko Island in West Greenland. Husky holds a 43.75% interest. This licence will expire on May 31, 2017.
On October 30, 2007, Husky completed Gas Sales Agreements between Husky Oil (Madura) Ltd. and PT Inti Parna Raya, PT Inti Alasindo Energy and PT Perusahaan Gas Negara (Persero) Tbk (“PNG”) for the sale of natural gas from the Madura BD natural gas and natural gas liquids field offshore Java, Indonesia. The BD field is expected to be developed after receipt of an extension to the production sharing contract.
On December 4, 2007, Husky completed construction of the Minnedosa ethanol plant. The plant is located at Minnedosa, Manitoba and has the capacity to produce 130 million litres of ethanol for blending with gasoline.
On December 5, 2007, Husky announced an agreement with BP Corporation North America Inc. (“BP”) to create an integrated North American oil sands business. The joint venture will be comprised of two partnerships, a Canadian oil
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sands partnership to be operated by Husky and a U.S. refining Limited Liability Company (“LLC”) to be operated by BP. Husky will contribute its Sunrise oil sands asset and BP will contribute its refinery located in Toledo, Ohio. The transaction, which is subject to the execution of definitive agreements and receipt of regulatory approval, is expected to close by the end of the first quarter of 2008 with an effective date of January 1, 2008.
Subsequent Events
Effective January 25, 2008, Husky acquired 110,000 acres of oil sands leases at McMullen located in the south west part of the Athabasca oil sands deposit in northern Alberta. The purchase price was $105 million for a 100% interest.
Events expected to occur during 2008
We expect to execute the definitive agreements, receive regulatory approvals and close the transaction with BP during the first quarter of 2008.
Business Environment Trends
There are a number of trends that are developing, which may have both long and short-term effects on the oil and gas industry in Canada. Conventional production of crude oil in the Western Canada Sedimentary Basin (“WCSB”) has been in decline since 2000 and will, according to industry forecasts(1), continue to decline. Since 2000 increased crude oil production from the WCSB has come from mining and in-situ production of bitumen and heavy crude oils. An increase in overall crude oil production from the WCSB beyond current production levels is forecast(1) to be non-conventional production. Natural gas exploration efforts are focused on the traditionally less accessible areas in the overthrust belt along the eastern slope of the Rocky Mountains, in the Northwest Territories, offshore the East Coast of Canada and smaller shallow gas deposits and coal bed methane in the WCSB.
The trend of volatile commodity prices is expected to continue. Natural gas prices are sensitive to regional supply/demand imbalances, regional industrial activity levels, weather patterns and access to cheaper sources of energy. As a result of numerous supply disruptions and increased demand from emerging economies oil prices have remained historically high. Notwithstanding supply disruptions or major policy changes in respect of greenhouse gas emissions, recent forecasts by the Energy Information Administration (“EIA”) in the United States indicates the possibility of crude oil production capacity increasing significantly over the next two and a half decades, particularly from Saudi Arabia, Russia, Africa and South America. The EIA also expect that petroleum will account for roughly the same proportion of the total energy supply. In terms of crude oil prices the EIA expects the price to remain, on average, at current levels in real terms (2007 dollars). The EIA does not explicitly provide any forecast on the range of fluctuation that prices might be subjected to, however, there is no reason to assume any change in the historical pattern of significant price volatility.
The EIA short-term energy outlook was published on January 8, 2008 and provides the following insights to the near term energy environment. World energy demand is expected to continue to grow slightly faster than supply in 2008 and then supply is expected to increase creating a narrow supply surplus in 2009. World oil consumption is expected to increase over 2007 consumption in both 2008 and 2009 primarily from Europe, Asia and Middle East countries. World oil supply from both OPEC and non-OPEC countries is expected to increase in 2008 and 2009 based on a number of projects that are currently underway. The pace and timing of the increase in supply will be subject to delays in key projects due to labour and supply shortages and uncertainty about production decline forecasts(2).
The EIA predicts that prices for refined products in 2008 will rise commensurate with the rise in crude oil prices. Currently in the United States 67% of the price of gasoline and 62% of the price of diesel fuel is for the crude oil feedstock. Consumption of refined petroleum products in the United States is predicted to rise by less than 1% over 2007 due to expected economic slowdown and forecasts for moderate weather. Current gasoline stocks are approximately 4% above the five year average and predicted to increase to approximately 8% above the five year average by the beginning of the peak driving season(3).
Notes:
(1) | “Canadian Crude Oil Production and Supply forecast,” July 2004, Canadian Association of Petroleum Producers “Oil Sands Technology Roadmap,” January 30, 2004, Alberta Chamber of Resources. |
(2) | Short-Term Energy Outlook January 8, 2008 Energy Information Administration U.S. Department of Energy. |
(3) | Short-Term Energy Outlook February 11, 2008 Energy Information Agency U.S. Department of Energy. |
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DESCRIPTION OF HUSKY’S BUSINESS
Husky is a publicly held integrated energy and energy related company headquartered in Calgary, Alberta.
Our business is conducted predominantly in three major business sectors — upstream, midstream and downstream.
Upstream includes exploration for, development and production of crude oil, natural gas and natural gas liquids. The Company’s upstream operations and key prospects are located in Western Canada, offshore Eastern Canada, Northwest Territories, offshore China, Indonesia and Greenland. (Upstream business segment)
Midstream includes upgrading of heavy crude oil feedstock into synthetic crude oil (upgrading); marketing of the Company’s and other producers’ crude oil, natural gas, natural gas liquids, sulphur and petroleum coke; and pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent and natural gas and cogeneration of electrical and thermal energy (infrastructure and marketing).
Downstream includes refining of light and heavy crude oil, production of ethanol, and marketing of refined petroleum products including gasoline, diesel, jet fuel, blending stocks, ethanol blended fuels, asphalt and the marketing of a wide variety of merchandise through convenience stores at our retail outlet locations. The downstream sector includes the Canadian refined products business segment and the U.S. refining and marketing business segment.
SOCIAL AND ENVIRONMENTAL POLICY
Husky’s environmental policy requires regular environmental audits to be conducted at its sites and facilities. Husky has established procedures designed to anticipate and to minimize adverse effects of its operations on the environment and for continued compliance with environmental legislation and minimize future and current costs. Husky’s policies apply equally to employees, subsidiaries and contractors except as required by applicable laws.
RISK FACTORS
The following factors should be considered in evaluating Husky:
Adequacy of crude oil and natural gas prices
Our results of operations and financial condition are dependent on the prices received for its crude oil and natural gas production. Lower prices for crude oil and natural gas could adversely affect the value and quantity of our oil and gas reserves. We have significant quantities of heavier grades of crude oil reserves that trade at a discount to light crude oil. Heavier grades of crude oil are typically more expensive to produce, process, transport and refine into high value refined products. Refining capacity for heavy crude oil is limited. As a result, wider price differentials could have adverse effects on financial performance and condition, could reduce the value and quantities of our heavier crude oil reserves and could delay or cancel projects that involve the development of heavier crude oil resources.
Prices for crude oil are based on world supply and demand. Supply and demand can be affected by a number of factors including, but not limited to, actions taken by the Organization of Petroleum Exporting Countries (“OPEC”), non-OPEC crude oil supply, social conditions in oil producing countries, the occurrence of natural disasters, general and specific economic conditions, prevailing weather patterns and the availability of alternate sources of energy.
Our natural gas production is located entirely in Western Canada and is, therefore, subject to North American market forces. North American natural gas supply and demand is affected by a number of factors including, but not limited to, the amount of natural gas available to specific market areas either from the well head or from storage facilities, prevailing weather patterns, the price of crude oil, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions.
Demand for Husky’s other products and services and the cost of required inputs
Our results of operations and financial condition are dependent on the price of refinery feedstock, the price of energy, the demand for refined petroleum products and electrical power and the ability of Husky to recover the increased cost of these inputs from the customer. We are also dependent on the demand for our pipeline and processing capacity.
Husky’s ability to replace reserves
Our future cash flow and cost of capital are dependent on its ability to replace its proved oil and gas reserves in a cost effective manner. Without economic reserve additions through exploration and development or acquisition Our production and, therefore, cash flow will decline. Without adequate proved reserves our ability to fund development and other capital expenditures with external sources of funds is diminished.
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Competition
The energy industry is currently experiencing high levels of activity driven by high commodity prices. The industry is highly competitive with respect to gaining access to the resources required to increase oil and gas reserves and production and gain access to markets. We compete with others to acquire prospective lands, to retain drilling capacity and field operating and construction services, to attract and retain experienced skilled management and oil and gas professionals, to obtain sufficient pipeline and other transportation capacity and to gain access to and retain adequate markets for our products and services. Our ability to successfully complete development projects could be adversely affected by an inability to acquire economic supplies and services due to competition. Subsequent increases in the cost of or delays in acquiring supplies and services could result in uneconomic projects. Our competitors comprise all types of energy companies, some of which have greater resources.
Delays and cost overruns of capital projects
We are involved in capital projects such as exploration programs, development of oil and gas properties, plant and facilities construction, expansion and modification. Project delays can adversely affect expected cash flow and overall project costs thereby eroding project economics. Risk factors include, but are not limited to:
• | availability of skilled labour; | |
• | availability of manufacturing capacity, supplies, material and equipment; | |
• | regulatory approvals; | |
• | faulty construction and design errors; | |
• | accidents, labour disruptions, bankruptcies and productivity issues affecting us directly or indirectly; and | |
• | unexpected changes in the scope of a project. |
Business interruption of operations
Our operations are subject to various risks with respect to normal operating conditions. These risks comprise, but are not limited to, explosions, blowouts, cratering, fires, severe storms and adverse weather, all forms of marine perils, release of toxic, combustible or explosive substances. These risks could cause loss of life, injury and destruction of public and our owned property.
The occurrence of any of the above listed events or others not listed could result in adverse financial performance and conditions that may not be fully recoverable from our insurers.
Foreign Exchange Risk
Our results are affected by the exchange rate between the Canadian and U.S. dollar. The majority of our revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. The majority of our expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2007, 93% or $2.6 billion of our long-term debt was denominated in U.S. dollars. The percentage of our long-term debt exposed to the U.S./Cdn exchange rate decreases to 80% when cross currency swaps are included. Additionally, U.S. $1.5 billion of our U.S. dollar denominated debt has been designated as a hedge of a net investment and the unrealized foreign exchange gain is recorded in Other Comprehensive Income, further reducing the long-term debt exposed to the U.S./Cdn exchange rate to 27%.
Environmental risks
All phases of the oil and natural gas business are subject to environmental regulation pursuant to a variety of federal, provincial and municipal laws and regulations, as well as international conventions (collectively, “environmental legislation”).
Environmental legislation imposes, among other things, restrictions, liabilities, and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that wells, facilities and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including
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exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability forclean-up costs and damages. We cannot be certain that the costs of complying with environmental legislation in the future will not have a material adverse effect on our financial condition and results of operations.
We anticipate that changes in environmental legislation may require reductions in emissions from its operations and result in increased capital expenditures. Further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on our financial condition and results of operations.
In 1994, the United Nations’ Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol, which requires the reduction of greenhouse gas emissions. On December 16, 2002, Canada ratified the Kyoto Protocol. In 2007, the world’s nations met again to gain the agreement of major countries that were not signatories to the Kyoto protocol such as the United States, China and India. This meeting in Bali, Indonesia did little to advance wider agreement on limiting greenhouse gases and set new limits for emissions, which expire in 2012 under the Kyoto Protocol. These initiatives may require Husky to significantly reduce emissions at its operations of greenhouse gases such as carbon dioxide, which may increase capital expenditures. Details regarding the implementation of the Kyoto Protocol and the ultimate completion of the Bali agreement in 2009 remain unclear.
The Federal Government of Canada has announced certain regulations in respect of green house gases and other pollutants. Although uncertain, these regulations may adversely affect our operations and increase our costs. These regulations may become more onerous over time as public and political pressures increase to implement initiatives that will effectively arrest the emission of greenhouse gases.
Changes to government fiscal policy may reduce our cash flow
All of our oil and gas production is subject to royalties. In 2007, the Alberta Government announced its decision with respect to recommendations issued by the Alberta Royalty Review Panel. The government projects an increase in royalties in 2010 of $1.4 billion under the new regime compared with the old regime. If the new Alberta fiscal regime is enacted as currently envisioned, our future net revenue from proved reserves estimated at December 31, 2007 before income taxes discounted at 10% would decrease by approximately 2%.
UPSTREAM OPERATIONS
Disclosures of Oil and Gas Activities
In the tables that follow, light crude oil (30° API and lighter), medium crude oil (between 20° and 30° API), heavy crude oil (20° and heavier but lighter than 10° API) and bitumen (10° API and heavier).
Production
2007 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
Crude Oil(mbbls/day) | ||||||||||||||||||||||||
Light crude oil and NGL | 138.7 | 26.4 | 99.5 | 125.9 | 12.7 | 0.1 | ||||||||||||||||||
Medium crude oil | 27.1 | 27.1 | — | 27.1 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 106.9 | 106.9 | — | 106.9 | — | — | ||||||||||||||||||
Total gross(1) | 272.7 | 160.4 | 99.5 | 259.9 | 12.7 | 0.1 | ||||||||||||||||||
Total net(1) | 233.0 | 134.6 | 88.2 | 222.8 | 10.1 | 0.1 | ||||||||||||||||||
Natural Gas(mmcf/day) | ||||||||||||||||||||||||
Gross(1) | 623.3 | 623.3 | — | 623.3 | — | — | ||||||||||||||||||
Net(1) | 492.3 | 492.3 | — | 492.3 | — | — | ||||||||||||||||||
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Production (continued)
2006 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
Crude Oil(mbbls/day) | ||||||||||||||||||||||||
Light crude oil and NGL | 111.0 | 30.3 | 68.5 | 98.8 | 12.1 | 0.1 | ||||||||||||||||||
Medium crude oil | 28.5 | 28.5 | — | 28.5 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 108.1 | 108.1 | — | 108.1 | — | — | ||||||||||||||||||
Total gross(1) | 247.6 | 166.9 | 68.5 | 235.4 | 12.1 | 0.1 | ||||||||||||||||||
Total net(1) | 220.4 | 143.8 | 66.5 | 210.3 | 10.0 | 0.1 | ||||||||||||||||||
Natural Gas(mmcf/day) | ||||||||||||||||||||||||
Gross(1) | 672.3 | 672.3 | — | 672.3 | — | — | ||||||||||||||||||
Net(1) | 528.2 | 528.2 | — | 528.2 | — | — | ||||||||||||||||||
2005 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
Crude Oil(mbbls/day) | ||||||||||||||||||||||||
Light crude oil and NGL | 64.6 | 31.3 | 17.2 | 48.5 | 16.0 | 0.1 | ||||||||||||||||||
Medium crude oil | 31.1 | 31.1 | — | 31.1 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 106.0 | 106.0 | — | 106.0 | — | — | ||||||||||||||||||
Total gross(1) | 201.7 | 168.4 | 17.2 | 185.6 | 16.0 | 0.1 | ||||||||||||||||||
Total net(1) | 175.7 | 146.0 | 15.1 | 161.1 | 14.5 | 0.1 | ||||||||||||||||||
Natural Gas(mmcf/day) | ||||||||||||||||||||||||
Gross(1) | 680.0 | 680.0 | — | 680.0 | — | — | ||||||||||||||||||
Net(1) | 488.5 | 488.5 | — | 488.5 | — | — | ||||||||||||||||||
Note:
(1) | Gross volumes are Husky’s lessor royalty, overriding royalty and working interest share of production before deduction of royalties. Net volumes are Husky’s gross volumes, less royalties. |
Revenue
2007 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
($ millions) | ||||||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||||
Light crude oil and NGL | 3,722 | 626 | 2,736 | 3,362 | 357 | 3 | ||||||||||||||||||
Medium crude oil | 504 | 504 | — | 504 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 1,567 | 1,567 | — | 1,567 | — | — | ||||||||||||||||||
Total gross | 5,793 | 2,697 | 2,736 | 5,433 | 357 | 3 | ||||||||||||||||||
Total net | 4,965 | 2,421 | 2,256 | 4,677 | 285 | 3 | ||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||
Gross | 1,430 | 1,430 | — | 1,430 | — | — | ||||||||||||||||||
Net | 1,200 | 1,200 | — | 1,200 | — | — | ||||||||||||||||||
Processing/Transportation | 64 | 64 | — | 64 | — | — | ||||||||||||||||||
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Revenue (continued)
2006 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
($ millions) | ||||||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||||
Light crude oil and NGL | 2,799 | 691 | 1,779 | 2,470 | 324 | 5 | ||||||||||||||||||
Medium crude oil | 515 | 515 | — | 515 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 1,575 | 1,575 | — | 1,575 | — | — | ||||||||||||||||||
Total gross | 4,889 | 2,781 | 1,779 | 4,560 | 324 | 5 | ||||||||||||||||||
Total net | 4,358 | 2,352 | 1,731 | 4,083 | 270 | 5 | ||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||
Gross | 1,601 | 1,601 | — | 1,601 | — | — | ||||||||||||||||||
Net | 1,319 | 1,319 | — | 1,319 | — | — | ||||||||||||||||||
Processing/Transportation | 96 | 69 | 27 | 96 | — | — | ||||||||||||||||||
2005 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
($ millions) | ||||||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||||
Light crude oil and NGL | 1,450 | 686 | 392 | 1,078 | 369 | 3 | ||||||||||||||||||
Medium crude oil | 493 | 493 | — | 493 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 1,203 | 1,203 | — | 1,203 | — | — | ||||||||||||||||||
Total gross | 3,146 | 2,382 | 392 | 2,774 | 369 | 3 | ||||||||||||||||||
Total net | 2,713 | 2,020 | 355 | 2,375 | 335 | 3 | ||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||
Gross | 2,000 | 2,000 | — | 2,000 | — | — | ||||||||||||||||||
Net | 1,594 | 1,594 | — | 1,594 | — | — | ||||||||||||||||||
Processing/Transportation | 61 | 58 | 3 | 61 | — | — | ||||||||||||||||||
Sales Prices
2007 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
Crude Oil($/bbl) | ||||||||||||||||||||||||
Light crude oil and NGL | 73.54 | 65.01 | 75.37 | 73.18 | 77.03 | 82.21 | ||||||||||||||||||
Medium crude oil | 51.12 | 51.12 | — | 51.12 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 40.19 | 40.19 | — | 40.19 | — | — | ||||||||||||||||||
Total crude oil and NGL | 58.24 | 46.12 | 75.37 | 57.31 | 77.03 | 82.21 | ||||||||||||||||||
Natural Gas($/mcf) | 6.19 | 6.19 | — | 6.19 | — | — |
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Sales Prices (continued)
2006 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
Crude Oil($/bbl) | ||||||||||||||||||||||||
Light crude oil and NGL | 69.06 | 62.46 | 71.18 | 68.50 | 73.58 | 74.96 | ||||||||||||||||||
Medium crude oil | 49.48 | 49.48 | — | 49.48 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 39.92 | 39.92 | — | 39.92 | — | — | ||||||||||||||||||
Total crude oil and NGL | 54.08 | 45.64 | 71.18 | 53.07 | 73.58 | 74.96 | ||||||||||||||||||
Natural Gas($/mcf) | 6.47 | 6.47 | — | 6.47 | — | — |
2005 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
Crude Oil($/bbl) | ||||||||||||||||||||||||
Light crude oil and NGL | 61.56 | 60.15 | 62.61 | 61.02 | 63.15 | 69.23 | ||||||||||||||||||
Medium crude oil | 43.44 | 43.44 | — | 43.44 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | 31.09 | 31.09 | — | 31.09 | — | — | ||||||||||||||||||
Total crude oil and NGL | 42.75 | 38.77 | 62.61 | 40.97 | 63.15 | 69.23 | ||||||||||||||||||
Natural Gas($/mcf) | 7.96 | 7.96 | — | 7.96 | — | — |
Capital Expenditures
2007 | ||||||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Indonesia | Libya | ||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||
Property acquisition | 172 | 172 | — | 172 | — | — | — | |||||||||||||||||||||
Exploration | 564 | 410 | 83 | 493 | 54 | 17 | — | |||||||||||||||||||||
Development | 1,652 | 1,449 | 197 | 1,646 | 1 | 5 | — | |||||||||||||||||||||
2,388 | 2,031 | 280 | 2,311 | 55 | 22 | — | ||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Indonesia | Libya | ||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||
Property acquisition | 193 | 192 | 1 | 193 | — | — | — | |||||||||||||||||||||
Exploration | 774 | 618 | 79 | 697 | 71 | 6 | — | |||||||||||||||||||||
Development | 1,660 | 1,361 | 279 | 1,640 | 14 | 5 | 1 | |||||||||||||||||||||
2,627 | 2,171 | 359 | 2,530 | 85 | 11 | 1 | ||||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Indonesia | Libya | ||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||
Property acquisition | 133 | 133 | — | 133 | — | — | — | |||||||||||||||||||||
Exploration | 445 | 324 | 66 | 390 | 55 | — | — | |||||||||||||||||||||
Development | 2,152 | 1,550 | 579 | 2,129 | 14 | 8 | 1 | |||||||||||||||||||||
2,730 | 2,007 | 645 | 2,652 | 69 | 8 | 1 | ||||||||||||||||||||||
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Capital Expenditures (continued)
Oil and Gas Netbacks(1)
2007 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
Crude Oil($/bbl) | ||||||||||||||||||||||||
Light crude oil | ||||||||||||||||||||||||
Sales revenue | 72.94 | 61.02 | 75.37 | 72.56 | 77.03 | 82.21 | ||||||||||||||||||
Royalties | 9.72 | 7.87 | 9.43 | 9.12 | 15.63 | — | ||||||||||||||||||
Operating costs | 5.70 | 13.24 | 4.07 | 5.89 | 3.68 | 23.12 | ||||||||||||||||||
Netback | 57.52 | 39.91 | 61.87 | 57.55 | 57.72 | 59.09 | ||||||||||||||||||
Medium crude oil | ||||||||||||||||||||||||
Sales revenue | 50.42 | 50.42 | — | 50.42 | — | — | ||||||||||||||||||
Royalties | 8.89 | 8.89 | — | 8.89 | — | — | ||||||||||||||||||
Operating costs | 13.92 | 13.92 | — | 13.92 | — | — | ||||||||||||||||||
Net back | 27.61 | 27.61 | — | 27.61 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | ||||||||||||||||||||||||
Sales revenue | 40.14 | 40.14 | — | 40.14 | — | — | ||||||||||||||||||
Royalties | 5.26 | 5.26 | — | 5.26 | — | — | ||||||||||||||||||
Operating costs | 12.81 | 12.81 | — | 12.81 | — | — | ||||||||||||||||||
Netback | 22.07 | 22.07 | — | 22.07 | — | — | ||||||||||||||||||
Total crude oil | ||||||||||||||||||||||||
Sales revenue | 57.60 | 45.13 | 75.37 | 56.65 | 77.03 | 82.21 | ||||||||||||||||||
Royalties | 7.87 | 6.30 | 9.43 | 7.49 | 15.63 | — | ||||||||||||||||||
Operating costs | 9.37 | 13.07 | 4.07 | 9.64 | 3.68 | 23.12 | ||||||||||||||||||
Netback | 40.36 | 25.76 | 61.87 | 39.52 | 57.72 | 59.09 | ||||||||||||||||||
Natural Gas($/mcf) | ||||||||||||||||||||||||
Sales revenue | 6.42 | 6.42 | — | 6.42 | — | — | ||||||||||||||||||
Royalties | 1.23 | 1.23 | — | 1.23 | — | — | ||||||||||||||||||
Operating costs | 1.39 | 1.39 | — | 1.39 | — | — | ||||||||||||||||||
Netback | 3.80 | 3.80 | — | 3.80 | — | — | ||||||||||||||||||
Equivalent Unit($boe) | ||||||||||||||||||||||||
Sales revenue | 52.41 | 42.57 | 75.37 | 51.54 | 77.03 | 82.21 | ||||||||||||||||||
Royalties | 7.74 | 6.72 | 9.43 | 7.46 | 15.63 | — | ||||||||||||||||||
Operating costs | 9.09 | 11.24 | 4.07 | 9.28 | 3.68 | 23.12 | ||||||||||||||||||
Netback | 35.58 | 24.61 | 61.87 | 34.80 | 57.72 | 59.09 | ||||||||||||||||||
Note:
(1) | Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification. |
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Oil and Gas Netbacks(1) (continued)
2006 | ||||||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||||||
Crude Oil($/bbl) | ||||||||||||||||||||||||||||
Light crude oil | ||||||||||||||||||||||||||||
Sales revenue | 68.51 | 59.89 | 71.18 | 67.87 | 73.58 | 74.96 | ||||||||||||||||||||||
Royalties | 4.49 | 7.34 | 1.95 | 3.52 | 12.33 | — | ||||||||||||||||||||||
Operating costs | 6.96 | 11.89 | 5.48 | 7.36 | 3.61 | 18.51 | ||||||||||||||||||||||
Netback | 57.06 | 40.66 | 63.75 | 56.99 | 57.64 | 56.45 | ||||||||||||||||||||||
Medium crude oil | ||||||||||||||||||||||||||||
Sales revenue | 48.97 | 48.97 | — | 48.97 | — | — | ||||||||||||||||||||||
Royalties | 8.61 | 8.61 | — | 8.61 | — | — | ||||||||||||||||||||||
Operating costs | 13.09 | 13.09 | — | 13.09 | — | — | ||||||||||||||||||||||
Net back | 27.27 | 27.27 | — | 27.27 | — | — | ||||||||||||||||||||||
Heavy crude oil & bitumen | ||||||||||||||||||||||||||||
Sales revenue | 39.91 | 39.91 | — | 39.91 | — | — | ||||||||||||||||||||||
Royalties | 5.16 | 5.16 | — | 5.16 | — | — | ||||||||||||||||||||||
Operating costs | 11.10 | 11.10 | — | 11.10 | — | — | ||||||||||||||||||||||
Netback | 23.65 | 23.65 | — | 23.65 | — | — | ||||||||||||||||||||||
Total crude oil | ||||||||||||||||||||||||||||
Sales revenue | 53.55 | 44.90 | 71.18 | 52.51 | 73.58 | 74.91 | ||||||||||||||||||||||
Royalties | 5.28 | 6.14 | 1.95 | 4.92 | 12.33 | — | ||||||||||||||||||||||
Operating costs | 9.53 | 11.60 | 5.48 | 9.83 | 3.61 | 18.51 | ||||||||||||||||||||||
Netback | 38.74 | 27.16 | 63.75 | 37.76 | 57.64 | 56.45 | ||||||||||||||||||||||
Natural Gas($/mcf) | ||||||||||||||||||||||||||||
Sales revenue | 6.65 | 6.65 | — | 6.65 | — | — | ||||||||||||||||||||||
Royalties | 1.37 | 1.37 | — | 1.37 | — | — | ||||||||||||||||||||||
Operating costs | 1.18 | 1.18 | — | 1.18 | — | — | ||||||||||||||||||||||
Netback | 4.10 | 4.10 | — | 4.10 | — | — | ||||||||||||||||||||||
Equivalent Unit($boe) | ||||||||||||||||||||||||||||
Sales revenue | 49.34 | 42.91 | 71.18 | 48.58 | 73.58 | 74.91 | ||||||||||||||||||||||
Royalties | 6.19 | 6.97 | 1.95 | 5.99 | 12.33 | — | ||||||||||||||||||||||
Operating costs | 8.77 | 9.79 | 5.48 | 8.98 | 3.61 | 18.51 | ||||||||||||||||||||||
Netback | 34.38 | 26.15 | 63.75 | 33.61 | 57.64 | 56.45 | ||||||||||||||||||||||
Note:
(1) | Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification. |
14
Table of Contents
Oil and Gas Netbacks(1) (continued)
2005 | ||||||||||||||||||||||||
Western | East | |||||||||||||||||||||||
Total | Canada | Coast | Canada | China | Libya | |||||||||||||||||||
Crude Oil($/bbl) | ||||||||||||||||||||||||
Light crude oil | ||||||||||||||||||||||||
Sales revenue | 61.86 | 60.74 | 62.61 | 61.41 | 63.15 | 69.23 | ||||||||||||||||||
Royalties | 7.22 | 8.66 | 5.91 | 7.67 | 5.93 | — | ||||||||||||||||||
Operating costs | 6.88 | 9.86 | 5.14 | 8.16 | 2.92 | 22.73 | ||||||||||||||||||
Netback | 47.76 | 42.22 | 51.56 | 45.58 | 54.30 | 46.50 | ||||||||||||||||||
Medium crude oil | ||||||||||||||||||||||||
Sales revenue | 43.67 | 43.67 | — | 43.67 | — | — | ||||||||||||||||||
Royalties | 7.77 | 7.77 | — | 7.77 | — | — | ||||||||||||||||||
Operating costs | 10.97 | 10.97 | — | 10.97 | — | — | ||||||||||||||||||
Net back | 24.93 | 24.93 | — | 24.93 | — | — | ||||||||||||||||||
Heavy crude oil & bitumen | ||||||||||||||||||||||||
Sales revenue | 31.22 | 31.22 | — | 31.22 | — | — | ||||||||||||||||||
Royalties | 3.75 | 3.75 | — | 3.75 | — | — | ||||||||||||||||||
Operating costs | 9.90 | 9.90 | — | 9.90 | — | — | ||||||||||||||||||
Netback | 17.57 | 17.57 | — | 17.57 | — | — | ||||||||||||||||||
Total crude oil | ||||||||||||||||||||||||
Sales revenue | 42.83 | 38.91 | 62.61 | 41.08 | 63.15 | 69.23 | ||||||||||||||||||
Royalties | 5.49 | 5.41 | 5.91 | 5.45 | 5.93 | — | ||||||||||||||||||
Operating costs | 9.13 | 10.10 | 5.14 | 9.65 | 2.92 | 22.73 | ||||||||||||||||||
Netback | 28.21 | 23.40 | 51.56 | 25.98 | 54.30 | 46.50 | ||||||||||||||||||
Natural Gas($/mcf) | ||||||||||||||||||||||||
Sales revenue | 8.02 | 8.02 | — | 8.02 | — | — | ||||||||||||||||||
Royalties | 1.76 | 1.76 | — | 1.76 | — | — | ||||||||||||||||||
Operating costs | 1.04 | 1.04 | — | 1.04 | — | — | ||||||||||||||||||
Netback | 5.22 | 5.22 | — | 5.22 | — | — | ||||||||||||||||||
Equivalent Unit($boe) | ||||||||||||||||||||||||
Sales revenue | 44.56 | 42.53 | 62.61 | 43.69 | 63.15 | 69.23 | ||||||||||||||||||
Royalties | 7.29 | 7.45 | 5.91 | 7.36 | 5.93 | — | ||||||||||||||||||
Operating costs | 8.12 | 8.59 | 5.14 | 8.39 | 2.92 | 22.73 | ||||||||||||||||||
Netback | 29.15 | 26.49 | 51.56 | 27.94 | 54.30 | 46.50 | ||||||||||||||||||
Note:
(1) | Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification. |
15
Table of Contents
Producing Wells
Oil Wells | Natural Gas Wells | Total | ||||||||||||||||||||||
Gross(1)(2) | Net(1) | Gross(1)(2) | Net(1) | Gross(1)(2) | Net(1) | |||||||||||||||||||
Canada | ||||||||||||||||||||||||
Alberta | 4,090 | 3,211 | 5,489 | 4,274 | 9,579 | 7,485 | ||||||||||||||||||
Saskatchewan | 5,479 | 4,514 | 1,192 | 1,085 | 6,671 | 5,599 | ||||||||||||||||||
British Columbia | 204 | 58 | 239 | 170 | 443 | 228 | ||||||||||||||||||
Newfoundland | 15 | 6 | — | — | 15 | 6 | ||||||||||||||||||
9,788 | 7,789 | 6,920 | 5,529 | 16,708 | 13,318 | |||||||||||||||||||
International | ||||||||||||||||||||||||
China | 29 | 12 | — | — | 29 | 12 | ||||||||||||||||||
Libya | 2 | 1 | — | — | 2 | 1 | ||||||||||||||||||
31 | 13 | — | — | 31 | 13 | |||||||||||||||||||
As at December 31, 2007 | 9,819 | 7,802 | 6,920 | 5,529 | 16,739 | 13,331 | ||||||||||||||||||
Canada | ||||||||||||||||||||||||
Alberta | 4,390 | 3,395 | 5,385 | 4,235 | 9,775 | 7,630 | ||||||||||||||||||
Saskatchewan | 5,076 | 4,118 | 1,084 | 1,028 | 6,160 | 5,146 | ||||||||||||||||||
British Columbia | 203 | 57 | 219 | 150 | 422 | 207 | ||||||||||||||||||
Newfoundland | 21 | 6 | — | — | 21 | 6 | ||||||||||||||||||
Northwest Territories | 5 | 1 | 5 | 1 | 10 | 2 | ||||||||||||||||||
9,695 | 7,577 | 6,693 | 5,414 | 16,388 | 12,991 | |||||||||||||||||||
International | ||||||||||||||||||||||||
China | 27 | 11 | — | — | 27 | 11 | ||||||||||||||||||
Libya | 2 | 1 | — | — | 2 | 1 | ||||||||||||||||||
29 | 12 | — | — | 29 | 12 | |||||||||||||||||||
As at December 31, 2006 | 9,724 | 7,589 | 6,693 | 5,414 | 16,417 | 13,003 | ||||||||||||||||||
Notes:
(1) | The number of gross wells is the total number of wells in which Husky owns a working interest. The number of net wells is the sum of the fractional interests owned in the gross wells. Producing wells were producing or capable of producing at December 31. |
(2) | The above table does not include producing wells in which Husky has no working interest but does have a royalty interest. At December 31, 2007, Husky had a royalty interest in 3,600 wells of which 1,200 were oil producers and 2,400 were gas producers. |
(3) | For purposes of the above 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 2007, there were 313 gross, 298 net oil wells and 892 gross, 738 net natural gas wells which were completed in two or more formations and from which production is not commingled. |
16
Table of Contents
Landholdings
Developed Acreage
Gross | Net | |||||||
(thousands of acres) | ||||||||
As at December 31, 2007 | ||||||||
Western Canada | ||||||||
Alberta | 3,102 | 2,610 | ||||||
Saskatchewan | 638 | 574 | ||||||
British Columbia | 183 | 115 | ||||||
Manitoba | — | — | ||||||
3,923 | 3,299 | |||||||
Northwest Territories and Arctic | — | — | ||||||
Eastern Canada | 42 | 9 | ||||||
3,965 | 3,308 | |||||||
China | 17 | 7 | ||||||
Libya | 7 | 2 | ||||||
3,989 | 3,317 | |||||||
As at December 31, 2006 | ||||||||
Western Canada | ||||||||
Alberta | 3,235 | 2,709 | ||||||
Saskatchewan | 592 | 531 | ||||||
British Columbia | 185 | 114 | ||||||
Manitoba | — | — | ||||||
4,012 | 3,354 | |||||||
Northwest Territories and Arctic | 7 | 1 | ||||||
Eastern Canada | 35 | 4 | ||||||
4,054 | 3,359 | |||||||
China | 17 | 7 | ||||||
Libya | 7 | 2 | ||||||
4,078 | 3,368 | |||||||
As at December 31, 2005 | ||||||||
Western Canada | ||||||||
Alberta | 3,146 | 2,633 | ||||||
Saskatchewan | 577 | 517 | ||||||
British Columbia | 182 | 112 | ||||||
Manitoba | — | — | ||||||
3,905 | 3,262 | |||||||
Northwest Territories and Arctic | 7 | 1 | ||||||
Eastern Canada | 35 | 4 | ||||||
3,947 | 3,267 | |||||||
China | 17 | 7 | ||||||
Libya | 7 | 2 | ||||||
3,971 | 3,276 | |||||||
17
Table of Contents
Landholdings (continued)
Undeveloped Acreage
Gross | Net | |||||||
(thousands of acres) | ||||||||
As at December 31, 2007 | ||||||||
Western Canada | ||||||||
Alberta | 4,118 | 3,600 | ||||||
Saskatchewan | 1,547 | 1,404 | ||||||
British Columbia | 888 | 610 | ||||||
Manitoba | 1 | 1 | ||||||
6,554 | 5,615 | |||||||
Northwest Territories and Arctic | 1,021 | 396 | ||||||
Eastern Canada | 2,429 | 1,566 | ||||||
10,004 | 7,577 | |||||||
China | 7,372 | 3,612 | ||||||
Indonesia | 1,742 | 1,742 | ||||||
Greenland | 8,471 | 5,984 | ||||||
27,589 | 18,915 | |||||||
As at December 31, 2006 | ||||||||
Western Canada | ||||||||
Alberta | 4,358 | 3,841 | ||||||
Saskatchewan | 1,654 | 1,513 | ||||||
British Columbia | 906 | 639 | ||||||
Manitoba | 1 | 1 | ||||||
6,919 | 5,994 | |||||||
Northwest Territories and Arctic | 884 | 239 | ||||||
Eastern Canada | 2,591 | 1,786 | ||||||
10,394 | 8,019 | |||||||
China | 7,637 | 3,742 | ||||||
Indonesia | 1,742 | 1,742 | ||||||
19,773 | 13,503 | |||||||
18
Table of Contents
Drilling Activity
Year ended December 31 | ||||||||||||||||||||||||
2007 | 2006 | 2005 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Western Canada Drilling | ||||||||||||||||||||||||
Exploration | ||||||||||||||||||||||||
Oil | 79 | 79 | 101 | 99 | 89 | 85 | ||||||||||||||||||
Gas | 114 | 92 | 330 | 192 | 392 | 196 | ||||||||||||||||||
Dry | 14 | 12 | 26 | 24 | 36 | 36 | ||||||||||||||||||
207 | 183 | 457 | 315 | 517 | 317 | |||||||||||||||||||
Development | ||||||||||||||||||||||||
Oil | 571 | 530 | 590 | 543 | 466 | 433 | ||||||||||||||||||
Gas | 343 | 251 | 565 | 490 | 610 | 551 | ||||||||||||||||||
Dry | 31 | 29 | 25 | 22 | 42 | 39 | ||||||||||||||||||
945 | 810 | 1,180 | 1,055 | 1,118 | 1,023 | |||||||||||||||||||
1,152 | 993 | 1,637 | 1,370 | 1,635 | 1,340 | |||||||||||||||||||
Present Activities
Exploratory | Development | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Wells Drilling(1) | ||||||||||||||||
Western Canada | 3 | 2.25 | 13 | 10.34 | ||||||||||||
Note:
(1) | Denotes wells that were drilling at December 31, 2007. |
Oil and Gas Reserves Disclosures
Husky’s oil and gas reserves as of December 31, 2007 are based on prices and costs in effect on that date and remain constant in future periods in accordance with the rules of the Financial Accounting Standards Board and the Securities and Exchange Commission (U.S.) and are prepared internally by Husky’s reserves evaluation staff. Husky uses a formalized process for determining, approving and booking reserves. This process provides for all reserves evaluations to be done on a consistent basis using established definitions and guidelines. Approval of any significant reserve additions and changes requires review by an internal panel of qualified reserves evaluators.
Audit of Oil and Gas Reserves
McDaniel & Associates Consultants Ltd., an independent firm of qualified oil and gas reserves evaluation engineers, was engaged to conduct an audit of Husky’s crude oil, natural gas and natural gas products reserves. McDaniel & Associates Consultants Ltd. issued an audit opinion stating that Husky’s internally generated proved and probable reserves and net present values based on forecast and constant price assumptions are, in aggregate, reasonable, and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices in the United States and as set out in the COGEH.
19
Table of Contents
Proved Reserves
Future | ||||||||||||||||||||||||
Net Cash Flows | ||||||||||||||||||||||||
Crude Oil & NGL(1) | Natural Gas(1) | Before Tax(1)(4) | ||||||||||||||||||||||
Gross(2) | Net(2) | Gross(2) | Net(2) | 0% | 10% | |||||||||||||||||||
(mmbbls) | (bcf) | ($ millions) | ||||||||||||||||||||||
Proved developed(3) | 492 | 415 | 1,780 | 1,494 | 27,003 | 17,557 | ||||||||||||||||||
Proved undeveloped(3)(5) | 157 | 137 | 411 | 360 | 6,236 | 3,425 | ||||||||||||||||||
Proved total(3) | 649 | 552 | 2,191 | 1,854 | 33,239 | 20,982 | ||||||||||||||||||
Notes:
(1) | Husky applied for and was granted an exemption from National Instrument51-101 “Standards of Disclosure for Oil and Gas Activities” to provide oil and gas reserves disclosures in accordance with the U.S. Securities and Exchange Commission guidelines and the U.S. Financial Accounting Standards Board disclosure standards. The information disclosed may differ from information prepared in accordance with National Instrument51-101. Husky’s internally generated oil and gas reserves data was audited by an independent firm of qualified reserves evaluators. |
(2) | Gross reserves are Husky’s lessor royalty, overriding royalty and working interest share of reserves, before deduction of royalties. Net reserves are gross reserves, less royalties. |
(3) | These reserve categories have the same meanings as those set out in SECRegulation S-X. |
(4) | The discounted future net cash flows at December 31, 2007 were based on the year-end spot NYMEX natural gas price of U.S. $7.11/mmbtu and on a spot WTI crude oil price of U.S. $95.98/bbl. |
(5) | Estimated future capital expenditures required to gain access to proved undeveloped reserves as at December 31, 2007 and 2006 were as follows: |
As at December 31, 2007 | ||||||||||||||||||||||||||||
Total | 2008 | 2009 | 2010 | 2011 | 2012 | Thereafter | ||||||||||||||||||||||
($ millions undiscounted) | ||||||||||||||||||||||||||||
Western Canada | 1,943 | 713 | 520 | 272 | 119 | 87 | 232 | |||||||||||||||||||||
Eastern Canada | 476 | 198 | 237 | 19 | — | — | 22 | |||||||||||||||||||||
2,419 | 911 | 757 | 291 | 119 | 87 | 254 | ||||||||||||||||||||||
As at December 31, 2006 | ||||||||||||||||||||||||||||
Total | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | ||||||||||||||||||||||
($ millions undiscounted) | ||||||||||||||||||||||||||||
Western Canada | 1,725 | 558 | 573 | 263 | 100 | 96 | 135 | |||||||||||||||||||||
Eastern Canada | — | — | — | — | — | — | — | |||||||||||||||||||||
1,725 | 558 | 573 | 263 | 100 | 96 | 135 | ||||||||||||||||||||||
(6) | On December 31, 2007, the date our oil and gas reserves were evaluated, the calculated price of Lloydminster heavy crude oil was $59.09 per barrel. Our heavy crude oil reserves were economic at that price and no negative price revision resulted. |
20
Table of Contents
Reconciliation of Proved Gross Reserves
Canada | International | Total | ||||||||||||||||||||||||||||||||||||||
East | ||||||||||||||||||||||||||||||||||||||||
Western Canada | Coast | |||||||||||||||||||||||||||||||||||||||
Light | Light | |||||||||||||||||||||||||||||||||||||||
Proved reserves, | Crude Oil | Medium | Heavy | Natural | Light | Crude Oil | Natural | Crude Oil | Natural | |||||||||||||||||||||||||||||||
before royalties(1) | & NGL | Crude Oil | Crude Oil | Gas | Bitumen | Crude Oil | & NGL | Gas | & NGL | Gas | ||||||||||||||||||||||||||||||
(mmbbls) | (mmbbls) | (mmbbls) | (bcf) | (mmbbls) | (mmbbls) | (mmbbls) | (bcf) | (mmbbls) | (bcf) | |||||||||||||||||||||||||||||||
End of 2004 | 171 | 86 | 105 | 2,169 | — | 47 | 20 | — | 429 | 2,169 | ||||||||||||||||||||||||||||||
Revisions | 3 | 9 | 121 | (65 | ) | — | 9 | 2 | — | 144 | (65 | ) | ||||||||||||||||||||||||||||
Purchases | — | — | 7 | 3 | — | — | — | — | 7 | 3 | ||||||||||||||||||||||||||||||
Sales | — | (3 | ) | (4 | ) | (9 | ) | — | — | — | — | (7 | ) | (9 | ) | |||||||||||||||||||||||||
Discoveries and extensions | 4 | 3 | 27 | 277 | 48 | 16 | 1 | — | 99 | 277 | ||||||||||||||||||||||||||||||
Improved recovery | 1 | 7 | — | 9 | — | 23 | — | — | 31 | 9 | ||||||||||||||||||||||||||||||
Production | (12 | ) | (11 | ) | (39 | ) | (248 | ) | — | (6 | ) | (6 | ) | — | (74 | ) | (248 | ) | ||||||||||||||||||||||
End of 2005 | 167 | 91 | 217 | 2,136 | 48 | 89 | 17 | — | 629 | 2,136 | ||||||||||||||||||||||||||||||
Revisions | (3 | ) | (1 | ) | (2 | ) | (87 | ) | (1 | ) | 31 | 2 | — | 26 | (87 | ) | ||||||||||||||||||||||||
Purchases | 1 | 1 | — | 25 | — | — | — | — | 2 | 25 | ||||||||||||||||||||||||||||||
Sales | (1 | ) | — | — | (3 | ) | — | — | — | — | (1 | ) | (3 | ) | ||||||||||||||||||||||||||
Discoveries and extensions | 7 | 5 | 37 | 314 | 13 | — | — | — | 62 | 314 | ||||||||||||||||||||||||||||||
Improved recovery | 6 | 1 | — | 3 | — | 12 | — | — | 19 | 3 | ||||||||||||||||||||||||||||||
Production | (11 | ) | (10 | ) | (39 | ) | (245 | ) | (25 | ) | (5 | ) | — | (90 | ) | (245 | ) | |||||||||||||||||||||||
End of 2006 | 166 | 87 | 213 | 2,143 | 60 | 107 | 14 | — | 647 | 2,143 | ||||||||||||||||||||||||||||||
Revisions | 1 | 4 | (8 | ) | 64 | — | 26 | 2 | — | 25 | 64 | |||||||||||||||||||||||||||||
Purchases | 1 | — | — | 36 | — | — | — | — | 1 | 36 | ||||||||||||||||||||||||||||||
Sales | (10 | ) | — | — | (23 | ) | — | — | — | — | (10 | ) | (23 | ) | ||||||||||||||||||||||||||
Discoveries and extensions | 8 | 6 | 37 | 189 | 11 | 19 | — | — | 81 | 189 | ||||||||||||||||||||||||||||||
Improved recovery | 2 | 1 | 1 | 10 | — | — | — | — | 4 | 10 | ||||||||||||||||||||||||||||||
Production | (9 | ) | (10 | ) | (38 | ) | (228 | ) | (1 | ) | (36 | ) | (5 | ) | — | (99 | ) | (228 | ) | |||||||||||||||||||||
End of 2007 | 159 | 88 | 205 | 2,191 | 70 | 116 | 11 | — | 649 | 2,191 | ||||||||||||||||||||||||||||||
Note:
(1) | Proved reserves are the estimated quantities of crude oil, natural gas and NGL which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. |
21
Table of Contents
Reserves and Production by Principal Area
Gross | ||||||||
Crude Oil and NGL(1) | Proved Reserves | Production | ||||||
(mmbbls) | (mbbls/day) | |||||||
Canada | ||||||||
Western Canada | ||||||||
British Columbia and Foothills | ||||||||
Alberta and BC Plains area | 29.2 | 5.2 | ||||||
Foothills Deep Gas area | 29.3 | 5.5 | ||||||
Ram River and Kaybob areas | 7.1 | 2.4 | ||||||
Northwest Alberta Plains | ||||||||
Rainbow Lake area | 76.1 | 7.4 | ||||||
Peace River Arch area | 4.3 | 1.5 | ||||||
East Central Alberta | ||||||||
North area | 2.4 | 0.5 | ||||||
South area | 2.6 | 0.8 | ||||||
Provost area | 37.5 | 15.4 | ||||||
Southern Alberta and Saskatchewan | ||||||||
South Alberta area | 25.2 | 8.0 | ||||||
South Saskatchewan area | 63.5 | 15.2 | ||||||
Lloydminster Area | ||||||||
Primary production | 102.9 | 77.4 | ||||||
Thermal production | 71.5 | 18.8 | ||||||
Oil Sands | 70.3 | 1.6 | ||||||
Other | 0.3 | 0.8 | ||||||
522.2 | 160.5 | |||||||
East Coast Canada | ||||||||
Terra Nova | 20.7 | 14.5 | ||||||
White Rose | 95.1 | 85.0 | ||||||
115.8 | 99.5 | |||||||
China | ||||||||
Wenchang | 10.9 | 12.7 | ||||||
648.9 | 272.7 | |||||||
Note:
(1) Gross crude oil and NGL reserves as at December 31, 2007 and average 2007 daily gross production of crude oil and NGL.
22
Table of Contents
Gross | ||||||||
Natural Gas(1) | Proved Reserves | Production | ||||||
(bcf) | (mmcf/day) | |||||||
Canada | ||||||||
Western Canada | ||||||||
British Columbia and Foothills | ||||||||
Alberta and BC Plains area | 125.7 | 50.7 | ||||||
Foothills Deep Gas area | 424.2 | 87.1 | ||||||
Ram River and Kaybob areas | 249.9 | 77.4 | ||||||
Northwest Alberta Plains | ||||||||
Rainbow Lake area | 434.1 | 78.0 | ||||||
Peace River Arch | — | 1.7 | ||||||
Northern Alberta area | 167.0 | 54.4 | ||||||
East Central Alberta | ||||||||
Provost area | 141.5 | 44.8 | ||||||
North area | 198.3 | 47.0 | ||||||
South area | 143.9 | 55.2 | ||||||
Southern Alberta and Saskatchewan | ||||||||
South Alberta area | 46.9 | 22.3 | ||||||
South Saskatchewan area | 186.3 | 55.2 | ||||||
Lloydminster Area | 72.8 | 41.7 | ||||||
Other | — | 7.8 | ||||||
2,190.6 | 623.3 | |||||||
Note:
(1) Gross natural gas reserves as at December 31, 2007 and average daily gross production of natural gas.
Probable Oil and Gas Reserves(1)
Canada | ||||||||||||||||||||
Western Canada | ||||||||||||||||||||
Conventional | Bitumen(2) | East Coast | International | Total | ||||||||||||||||
(mmbbls) | ||||||||||||||||||||
Crude Oil & NGL | ||||||||||||||||||||
2007 | 149 | 1,765 | 100 | 25 | 2,039 | |||||||||||||||
2006 | 144 | 1,127 | 79 | 9 | 1,359 | |||||||||||||||
2005 | 146 | 903 | 118 | 13 | 1,180 | |||||||||||||||
Natural Gas | ||||||||||||||||||||
(bcf) | ||||||||||||||||||||
2007 | 473 | 516 | 989 | |||||||||||||||||
2006 | 390 | 93 | 483 | |||||||||||||||||
2005 | 407 | 167 | 574 | |||||||||||||||||
Barrels of Oil Equivalent | ||||||||||||||||||||
(mmboe) | ||||||||||||||||||||
2007 | 228 | 1,765 | 100 | 111 | 2,204 | |||||||||||||||
2006 | 209 | 1,127 | 79 | 25 | 1,440 | |||||||||||||||
2005 | 213 | 903 | 118 | 41 | 1,275 |
Notes:
(1) | The probable reserves presented have been prepared, using constant prices and costs, in accordance with NI51-101. |
(2) | Bitumen reserves were based on constant prices calculated in accordance with the Canadian Securities Administrators Staff Notice51-315 Guidance Regarding the Determination of Constant Prices for Bitumen Reserves under National Instrument51-101 Standards of Disclosure for Oil and Gas Activities (the “Staff Notice). |
23
Table of Contents
(4) | The SEC generally permits oil and gas registrants to disclose only reserves that meet the standards for proved reserves. Due to the higher uncertainty associated with probable reserves, disclosure or reference to probable reserves does not meet the standards for the inclusion in a document filed with the SEC. The disclosure of probable reserves is included herein in accordance with NI51-101. |
Disclosure about Oil and Gas Producing Activities — Statement of Financial Accounting Standards No. 69
The following disclosures have been prepared in accordance with FASB Statement No. 69 “Disclosures about Oil and Gas Producing Activities” (“FAS 69”):
Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.
Canadian provincial royalties are determined based on a graduated percentage scale, which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and our estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause our share of future production from Canadian reserves to be materially different from that presented.
Subsequent to December 31, 2007, no major discovery or other favourable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
Results of Operations for Producing Activities(1)(2)
Canada | International | Total | ||||||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||||||||||||
($ millions except per boe amounts) | ||||||||||||||||||||||||||||||||||||
Oil and gas production revenue | 5,998 | 5,567 | 4,085 | 288 | 274 | 337 | 6,286 | 5,841 | 4,422 | |||||||||||||||||||||||||||
Operating costs | ||||||||||||||||||||||||||||||||||||
Lease operating expenses | 1,292 | 1,215 | 925 | 21 | 22 | 18 | 1,313 | 1,237 | 943 | |||||||||||||||||||||||||||
Production taxes | 64 | 69 | 56 | — | — | — | 64 | 69 | 56 | |||||||||||||||||||||||||||
Asset retirement obligation accretion | 38 | 37 | 28 | — | — | — | 38 | 37 | 28 | |||||||||||||||||||||||||||
1,394 | 1,321 | 1,009 | 21 | 22 | 18 | 1,415 | 1,343 | 1,027 | ||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1,563 | 1,426 | 1,102 | 52 | 50 | 42 | 1,615 | 1,476 | 1,144 | |||||||||||||||||||||||||||
Earnings before taxes | 3,041 | 2,820 | 1,974 | 215 | 202 | 277 | 3,256 | 3,022 | 2,251 | |||||||||||||||||||||||||||
Income tax | 994 | 982 | 730 | 70 | 72 | 106 | 1,064 | 1,054 | 836 | |||||||||||||||||||||||||||
Results of operations | 2,047 | 1,838 | 1,244 | 145 | 130 | 171 | 2,192 | 1,968 | 1,415 | |||||||||||||||||||||||||||
Amortization rate per gross boe | 11.77 | 11.24 | 10.10 | 11.10 | 11.24 | 7.21 | 11.75 | 11.24 | 9.95 | |||||||||||||||||||||||||||
Amortization rate per net boe | 14.06 | 13.09 | 12.45 | 14.01 | 13.50 | 7.96 | 14.05 | 13.10 | 12.19 |
Notes:
(1) | The costs in this schedule exclude corporate overhead, interest expense and other operating costs, which are not directly related to producing activities. |
(2) | Under U.S. GAAP, the depreciation, depletion and amortization for Canadian producing activities for 2007 amounted to $1,507 million (2006 — $1,362 million; 2005 — $1,036 million). Income taxes for Canadian producing activities under U.S. GAAP for 2007 amounted to $1,011 million (2006 — $1,005 million; 2005 — $755 million). |
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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities(1)
�� | ||||||||||||
Canada | International | Total | ||||||||||
($ millions) | ||||||||||||
2007 | ||||||||||||
Property acquisition | ||||||||||||
Proved | 126 | — | 126 | |||||||||
Unproved | 46 | — | 46 | |||||||||
Exploration | 580 | 70 | 650 | |||||||||
Development | 1,559 | 6 | 1,565 | |||||||||
Capitalized interest | 6 | — | 6 | |||||||||
Total costs incurred | 2,317 | 76 | 2,393 | |||||||||
Less: Proved acquisitions | 126 | — | 126 | |||||||||
Capitalized interest | 6 | — | 6 | |||||||||
Finding and development costs | 2,185 | 76 | 2,261 | |||||||||
2006 | ||||||||||||
Property acquisition | ||||||||||||
Proved | 97 | — | 97 | |||||||||
Unproved | 96 | — | 96 | |||||||||
Exploration | 697 | 77 | 774 | |||||||||
Development | 1,637 | 20 | 1,657 | |||||||||
Capitalized interest | 23 | — | 23 | |||||||||
Total costs incurred | 2,550 | 97 | 2,647 | |||||||||
Less: Proved acquisitions | 97 | — | 97 | |||||||||
Capitalized interest | 23 | — | 23 | |||||||||
Finding and development costs | 2,430 | 97 | 2,527 | |||||||||
2005 | ||||||||||||
Property acquisition | ||||||||||||
Proved | 68 | — | 68 | |||||||||
Unproved | 65 | — | 65 | |||||||||
Exploration | 390 | 55 | 445 | |||||||||
Development | 2,042 | 23 | 2,065 | |||||||||
Capitalized interest | 112 | — | 112 | |||||||||
Total costs incurred | 2,677 | 78 | 2,755 | |||||||||
Less: Proved acquisitions | 68 | — | 68 | |||||||||
Capitalized interest | 112 | — | 112 | |||||||||
Finding and development costs | 2,497 | 78 | 2,575 | |||||||||
Note:
(1) | Development costs incurred exclude actual retirement expenditures and include asset retirement obligation incurred. Asset retirement obligation incurred for 2007 was $39 million (2006 — $45 million; 2005 — $51 million). |
Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.
Exploration costs include the costs of geological and geophysical activity, retaining undeveloped properties and drilling and equipping exploration wells.
Development costs include the costs of drilling and equipping development wells, facilities to extract, treat and gather and store oil and gas and settle the related asset retirement obligations.
Exploration and development costs include administrative costs and depreciation of support equipment directly associated with these activities.
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The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2007, by the year in which the costs were incurred:
Prior to | ||||||||||||||||||||
Withheld Costs | Total | 2007 | 2006 | 2005 | 2005 | |||||||||||||||
($ millions) | ||||||||||||||||||||
Property acquisitions | ||||||||||||||||||||
Canada | 67 | — | 67 | — | — | |||||||||||||||
International | 63 | — | — | — | 63 | |||||||||||||||
130 | — | 67 | — | 63 | ||||||||||||||||
Exploration | ||||||||||||||||||||
Canada | 1,088 | 426 | 398 | 264 | — | |||||||||||||||
International | 143 | 67 | 70 | — | 6 | |||||||||||||||
1,231 | 493 | 468 | 264 | 6 | ||||||||||||||||
Development | ||||||||||||||||||||
Canada | 695 | 378 | 317 | — | — | |||||||||||||||
International | 37 | 4 | 5 | 6 | 22 | |||||||||||||||
732 | 382 | 322 | 6 | 22 | ||||||||||||||||
Capitalized interest | ||||||||||||||||||||
Canada | 104 | 6 | 58 | 39 | 1 | |||||||||||||||
2,197 | 881 | 915 | 309 | 92 | ||||||||||||||||
Capitalized Costs Relating to Oil and Gas Producing Activities
Canada | International | Total | ||||||||||
($ millions) | ||||||||||||
2007 | ||||||||||||
Proved properties(1) | 20,830 | 584 | 21,414 | |||||||||
Unproved properties | 1,954 | 243 | 2,197 | |||||||||
22,784 | 827 | 23,611 | ||||||||||
Accumulated DD&A | 9,500 | 456 | 9,956 | |||||||||
Net Capitalized Costs(2) | 13,284 | 371 | 13,655 | |||||||||
2006 | ||||||||||||
Proved properties(1) | 19,087 | 586 | 19,673 | |||||||||
Unproved properties | 1,932 | 165 | 2,097 | |||||||||
21,019 | 751 | 21,770 | ||||||||||
Accumulated DD&A | 8,141 | 404 | 8,545 | |||||||||
Net Capitalized Costs(2) | 12,878 | 347 | 13,225 | |||||||||
2005 | ||||||||||||
Proved properties(1) | 16,195 | 528 | 16,723 | |||||||||
Unproved properties | 2,317 | 127 | 2,444 | |||||||||
18,512 | 655 | 19,167 | ||||||||||
Accumulated DD&A | 6,729 | 354 | 7,083 | |||||||||
Net Capitalized Costs(2) | 11,783 | 301 | 12,084 | |||||||||
Notes:
(1) | Capitalized costs related to proved properties include the asset retirement obligations. The asset retirement obligations for the years presented were as follows: |
Canada | International | Total | ||||||||||
($ millions) | ||||||||||||
2007 | 454 | 6 | 460 | |||||||||
2006 | 415 | 6 | 421 | |||||||||
2005 | 370 | 6 | 376 |
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(2) | The net capitalized costs for Canadian oil and gas exploration, development and producing activities under U.S. GAAP for 2007 were $12,911 million (2006 — $12,449 million, 2005 — $11,290 million). The net capitalized costs for International property oil & gas exploration, development and producing activities under U.S. GAAP for 2007 were $370 million (2006 — $346 million, 2005 — $300 million). Please refer to theForm 40-F for an explanation of the differences between Canadian and U.S. GAAP for oil and gas activities. |
Oil and Gas Reserve Information
In Canada, our proved crude oil, natural gas liquids and natural gas reserves are located in the provinces of Alberta, Saskatchewan, British Columbia, and offshore the East Coast. Our international proved reserves are located in China and Libya.
Canada | International | Total | ||||||||||||||||||||||
Crude | Natural | Crude | Natural | Crude | Natural | |||||||||||||||||||
Reserves | Oil & NGL | Gas | Oil & NGL | Gas | Oil & NGL | Gas | ||||||||||||||||||
(mmbbls) | (bcf) | (mmbbls) | (bcf) | (mmbbls) | (bcf) | |||||||||||||||||||
Net proved reserves(1)(2)(3)(4) | ||||||||||||||||||||||||
End of year 2004 | 357 | 1,788 | 18 | — | 375 | 1,788 | ||||||||||||||||||
Revisions | 129 | (75 | ) | 2 | — | 131 | (75 | ) | ||||||||||||||||
Purchases | 6 | 2 | — | — | 6 | 2 | ||||||||||||||||||
Sales | (7 | ) | (7 | ) | — | — | (7 | ) | (7 | ) | ||||||||||||||
Improved recovery | 29 | 6 | — | — | 29 | 6 | ||||||||||||||||||
Discoveries and extensions | 94 | 230 | 1 | — | 95 | 230 | ||||||||||||||||||
Production | (59 | ) | (173 | ) | (5 | ) | — | (64 | ) | (173 | ) | |||||||||||||
End of year 2005 | 549 | 1,771 | 16 | — | 565 | 1,771 | ||||||||||||||||||
Revisions | 9 | (71 | ) | — | — | 9 | (71 | ) | ||||||||||||||||
Purchases | 2 | 21 | — | — | 2 | 21 | ||||||||||||||||||
Sales | — | (2 | ) | — | — | — | (2 | ) | ||||||||||||||||
Improved recovery | 16 | 2 | — | — | 16 | 2 | ||||||||||||||||||
Discoveries and extensions | 56 | 267 | — | — | 56 | 267 | ||||||||||||||||||
Production | (77 | ) | (189 | ) | (4 | ) | — | (81 | ) | (189 | ) | |||||||||||||
End of year 2006 | 555 | 1,799 | 12 | — | 567 | 1,799 | ||||||||||||||||||
Revisions | 3 | 61 | — | — | 3 | 61 | ||||||||||||||||||
Purchases | 1 | 29 | — | — | 1 | 29 | ||||||||||||||||||
Sales | (9 | ) | (18 | ) | — | — | (9 | ) | (18 | ) | ||||||||||||||
Improved recovery | 4 | 8 | — | — | 4 | 8 | ||||||||||||||||||
Discoveries and extensions | 71 | 155 | — | — | 71 | 155 | ||||||||||||||||||
Production | (81 | ) | (180 | ) | (4 | ) | — | (85 | ) | (180 | ) | |||||||||||||
End of year 2007 | 544 | 1,854 | 8 | — | 552 | 1,854 | ||||||||||||||||||
Net proved developed reserves,(1)(2)(3)(4) | ||||||||||||||||||||||||
End of year 2004 | 299 | 1,436 | 18 | — | 317 | 1,436 | ||||||||||||||||||
End of year 2005 | 327 | 1,413 | 15 | — | 342 | 1,413 | ||||||||||||||||||
End of year 2006 | 442 | 1,424 | 12 | — | 454 | 1,424 | ||||||||||||||||||
End of year 2007 | 407 | 1,494 | 8 | — | 415 | 1,494 |
Notes:
(1) | Net reserves are the Company’s lessor royalty, overriding royalty and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production. |
(2) | Reserves are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations from a given date forward, by known technology, under existing operating conditions and prices in effect at year end. |
(3) | Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. |
(4) | Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required. |
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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed utilizing procedures prescribed by FAS 69 and based on crude oil and natural gas reserve and production volumes estimated by our reserves evaluation staff. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating Husky or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of Husky’s reserves.
The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2007 was based on the NYMEX year-end natural gas spot price of U.S. $7.11/mmbtu (2006 — U.S. $5.51/mmbtu; 2005 — U.S. $9.52/mmbtu) and on crude oil prices computed with reference to the year-end WTI spot price of U.S. $95.98/bbl (2006 — U.S. $60.85/bbl; 2005 — U.S. $61.06/bbl).
Canada(1) | International(1) | Total(1) | ||||||||||||||||||||||||||||||||||
Standardized Measure | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Future cash inflows | 49,383 | 37,006 | 40,066 | 952 | 900 | 999 | 50,335 | 37,906 | 41,065 | |||||||||||||||||||||||||||
Future production costs | 12,394 | 10,915 | 10,259 | 136 | 143 | 108 | 12,530 | 11,058 | 10,367 | |||||||||||||||||||||||||||
Future development costs | 4,550 | 3,406 | 3,171 | 16 | 14 | 14 | 4,566 | 3,420 | 3,185 | |||||||||||||||||||||||||||
Future income taxes | 9,022 | 6,934 | 9,000 | 252 | 234 | 272 | 9,274 | 7,168 | 9,272 | |||||||||||||||||||||||||||
Future net cash flows | 23,417 | 15,751 | 17,636 | 548 | 509 | 605 | 23,965 | 16,260 | 18,241 | |||||||||||||||||||||||||||
Annual 10% discount factor | 9,039 | 6,045 | 7,115 | 93 | 93 | 123 | 9,132 | 6,138 | 7,238 | |||||||||||||||||||||||||||
Standardized measure of discounted | ||||||||||||||||||||||||||||||||||||
Future net cash flows | 14,378 | 9,706 | 10,521 | 455 | 416 | 482 | 14,833 | 10,122 | 11,003 | |||||||||||||||||||||||||||
Note:
(1) | The schedules above are calculated using year-end prices, costs, statutory income tax rates and existing proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded. |
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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves
to Proved Oil and Gas Reserves
Canada(1) | International(1) | Total(1) | ||||||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Present value at January 1 | 9,706 | 10,521 | 4,745 | 416 | 482 | 460 | 10,122 | 11,003 | 5,205 | |||||||||||||||||||||||||||
Sales and transfers, net of production costs | (4,696 | ) | (4,318 | ) | (3,101 | ) | (270 | ) | (257 | ) | (320 | ) | (4,966 | ) | (4,575 | ) | (3,421 | ) | ||||||||||||||||||
Net change in sales and transfer prices, net of development and production costs | 7,380 | (1,721 | ) | 5,479 | 265 | 126 | 155 | 7,645 | (1,595 | ) | 5,634 | |||||||||||||||||||||||||
Development cost incurred that reduced future development costs | 1,772 | 1,640 | 2,129 | 6 | 20 | 23 | 1,778 | 1,660 | 2,152 | |||||||||||||||||||||||||||
Changes in estimated future development costs | (2,157 | ) | (1,526 | ) | (2,326 | ) | (4 | ) | (19 | ) | (22 | ) | (2,161 | ) | (1,545 | ) | (2,348 | ) | ||||||||||||||||||
Extensions, discoveries and improved recovery, net of related costs | 2,226 | 1,666 | 2,027 | 13 | — | 24 | 2,239 | 1,666 | 2,051 | |||||||||||||||||||||||||||
Revisions of quantity estimates | 868 | 563 | 2,550 | (13 | ) | (27 | ) | 110 | 855 | 536 | 2,660 | |||||||||||||||||||||||||
Accretion of discount | 1,422 | 1,601 | 762 | 61 | 70 | 68 | 1,483 | 1,671 | 830 | |||||||||||||||||||||||||||
Sale of reserves in place | (256 | ) | (19 | ) | (62 | ) | — | — | — | (256 | ) | (19 | ) | (62 | ) | |||||||||||||||||||||
Purchase of reserves in place | 114 | 65 | 36 | — | — | — | 114 | 65 | 36 | |||||||||||||||||||||||||||
Changes in timing of future net cash flows and other | (575 | ) | 263 | 889 | — | (5 | ) | (13 | ) | (575 | ) | 258 | 876 | |||||||||||||||||||||||
Net change in income taxes | (1,426 | ) | 971 | (2,607 | ) | (19 | ) | 26 | (3 | ) | (1,445 | ) | 997 | (2,610 | ) | |||||||||||||||||||||
Net increase (decrease) | 4,672 | (815 | ) | 5,776 | 39 | (66 | ) | 22 | 4,711 | (881 | ) | 5,798 | ||||||||||||||||||||||||
Present value at December 31 | 14,378 | 9,706 | 10,521 | 455 | 416 | 482 | 14,833 | 10,122 | 11,003 | |||||||||||||||||||||||||||
Note:
(1) | The schedules above are calculated using year-end prices, costs, statutory income tax rates and existing proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded. |
Description of Major Properties and Facilities
Our portfolio of upstream assets includes properties with reserves of light (30° API and lighter), medium (between 20° and 30° API) heavy (20° API and heavier but lighter than 10° API) and bitumen (10° API and heavier) gravity crude oil, NGL, natural gas and sulphur.
Lloydminster Heavy Oil and Gas
Our heavy oil assets are concentrated in a large producing area in the Lloydminster Alberta/Saskatchewan area. We maintain a land position of approximately 1.75 million acres within this area, of which approximately 65% is undeveloped. Approximately 92% of our proved reserves in the region are contained in the heavy crude oil producing fields of Pikes Peak, Edam, Tangleflags, Celtic, Bolney, Westhazel, Big Gully, Hillmond, Mervin, Marwayne, Lashburn, Gully Lake and Rush Lake, and in the medium gravity crude oil producing fields of Wildmere and Wainwright. These fields contain accumulations of heavy crude oil at relatively shallow depths.
We currently produce from oil and gas wells ranging in depth from 450 to 650 metres and hold a 100% working interest in the majority of these wells. We produce heavy oil from the Lloydminster area using a variety of techniques, including standard primary production methods, as well as steam injection, horizontal well technology and Steam Assisted Gravity Drainage (“SAGD”). We have increased primary production from the area through cold production techniques which utilize progressive cavity pumps capable of simultaneous production of sand and heavy oil from
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unconsolidated formations. Our gross heavy and medium crude oil production from the area totalled 96.2 mbbls/day in 2007. Of the total production, 74.6 mbbls/day was primary production of heavy crude oil, 18.8 mbbls/day was production from our thermal operations at Pikes Peak (cyclic steam), Bolney/Celtic (SAGD) and the Pikes Peak South pilot (SAGD), and 2.8 mbbls/day was from the medium gravity waterflooded fields in the Wainwright and Wildmere areas. We believe that the future growth from this area will be driven by primary heavy oil production, including cold production, and new thermal projects.
In the Lloydminster area we own and operate 19 oil treating facilities, all of which are tied into our heavy oil pipeline systems. These pipeline systems transport heavy crude oil from the field locations to our Lloydminster asphalt refinery, to the Husky Lloydminster Upgrader and to the Enbridge Pipeline, Express Pipeline and Inter Pipeline Fund systems at Hardisty, Alberta.
We are focused on increasing our heavy oil production and believe that our undeveloped land position coupled with the application of improved technologies will sustain heavy oil production in the Lloydminster area.
We also produce natural gas from numerous small shallow natural gas pools in the Lloydminster area (approximately 73 bcf of proved reserves). Our total gross natural gas production from the area during 2007 was 41.7 mmcf/day.
Lloydminster Area
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British Columbia Foothills/Northwest Plains
Rainbow Lake District
Rainbow Lake, located approximately 700 kilometres north-west of Edmonton, Alberta, is the site of our largest light oil production operation in Western Canada. Husky operates a number of crude oil pools in the Rainbow basin, with an average working interest of 54%. Our production in this area is derived from more than 50 oil and gas pools.
We use secondary and tertiary oil recovery methods extensively in the Rainbow Lake district. These methods include injecting water, natural gas and NGL into the oil reservoirs to enhance crude oil recovery. The use of tertiary recovery programs, such as the miscible flood used at Rainbow Lake, has increased the estimated amount recoverable from discovered petroleum initially in-place from 50% to 70% in certain pools. Historically, only small volumes of gas and NGL have been marketed from the Rainbow Lake district prior to 2002. In 2003, we initiated the recovery of natural gas from several pools. NGL recovery is forecast to begin in the2008-2010 timeframe and is expected to generate revenues as the crude oil production from the pools is completed. We use horizontal drilling techniques, including the re-entry of existing well bores, to maintain the level of crude oil production and to increase recovery rates. We plan to continue exploration efforts to supplement our development initiatives in the Rainbow Lake district. Husky’s gross production from this area averaged 7.1 mbbls/day of light crude oil and NGL and 27.4 mmcf/day of natural gas during 2007.
We hold a 50% interest in, and operate, the Rainbow Lake processing plant. The processing design rate capacity of the plant is 69 mbbls/day of crude oil and water and 230 mmcf/day of raw gas. The extraction design capacity is 17 mbbls/day of NGL.
Husky also has a 100% interest in a compression and dehydration facility at Bivouac that has a capacity to process 20 mmcf/day. In 2007 throughput at this facility averaged 16.3 mmcf/day. Our strategy in respect of this area is to drill and tie-in eight to ten development wells per year to fully load the facility.
We hold an interest in two significant non-operated properties in the Rainbow Lake District. They include the Ekwan/Sierra property in north-eastern British Columbia and the Bistcho property in Northwest Alberta. Our gross production from these properties currently averages 11.7 mmcf/day of natural gas and 47 bbls/day of liquid hydrocarbons. We also hold a working interest in the Encana Sierra gas plant and the Paramount Bistcho gas plant. We are active in both these areas with development and exploration drilling. In these two areas we hold in excess of 200,000 acres of undeveloped land.
North East Shallow Gas District
The North East Shallow Gas District is located approximately 200 kilometres north-east of Edmonton, Alberta. Natural gas is produced from the Clearwater, Colony, McMurray and Wabasca or a combination of these zones that lie at a depth of approximately 600 metres. In 2007, our gross natural gas production from this district averaged 56.6 mmcf/day. Our largest property in the district is at Muskwa, which consists of a 32 mmcf/day dehydrator facility, 6,255 horsepower of compression and a gathering system that collects natural gas from an area seven townships in size. Our gross production from Muskwa averaged 10.5 mmcf/day in 2007. Husky completed the acquisition of Trilogy Energy’s Martin Creek property in May 2007, which added 12.7 mmcf/day of natural gas production to this district. Our plans for 2008 are to continue to focus on recompletions and work-overs to increase production and add reserves at a low unit cost and take advantage of existing infrastructure and capacity.
High Level District
The High Level district of Alberta is approximately 600 kilometres northwest of Edmonton, Alberta. We are the operator and hold close to 100% working interests in our properties. The area contains shallow Bluesky gas reservoirs that are characterized as low deliverability and low decline. Gross production from this area in 2007 averaged 22.4 mmcf/day of natural gas.
Ram River District
The Ram River district is located in west central Alberta and includes the large Blackstone, Ricinus and Clearwater/Limestone natural gas fields.
The Blackstone field is the most prolific of these fields and contains four high deliverability natural gas wells, capable of combined raw gas production of 35.5 mmcf/day. We hold a 34% interest in two unitized wells, a 24% and a
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50% interest, respectively, in twonon-unit wells, and act as the contract operator of the Blackstone field. Production from the area is processed at the Ram River gas plant.
We hold an average 72% interest in and operate the Ram River sour gas plant and related processing facilities. The Ram River plant has the capacity to process 622 mmcf/day of sour gas, resulting in sales gas capacity of 525 mmcf/day. The plant also has the capacity to produce in excess of 2.8 mlt/day of sulphur from raw gas. During 2007, the plant operated at approximately 75% of its design rate capacity. The Ram River plant processes in excess of 10% of our total gross natural gas production. This includes an average of 39 mmcf/day of our gross production from the Blackstone, Brown Creek, Cordel and Stolberg fields and an average of 17.3 mmcf/day of our gross production from Ricinus and Clearwater/Limestone and Benjamin fields. In addition we process third-party volumes. Gross production from the Ferrier and North Blackstone area, which is processed at other gas plants, averaged 10.1 mmcf/day of natural gas, bringing our total gross production of natural gas from the Ram River district to 77.4 mmcf/day in 2007. Our 2008 plans for the Ram River district include continued exploration and development drilling in Ferrier and North Blackstone including evaluation of deeper targets.
Our sour gas pipeline network supports the Ram River plant. We operate a network of 845 kilometres of sour gas pipelines in the Ram River district and hold a 30% interest in 684 kilometres of this pipeline system. The sour gas processed at the Ram River plant is produced from 18 sour gas fields located as far as 145 kilometres from the Ram River plant.
We believe that the Ram River plant and the extensive infrastructure of gathering pipelines, transmission systems and rail lines, which support the plant, represents a strategic base for natural gas exploration and development planned in this part of the foothills region.
In addition, this region is an active exploration and production area for other producers and provides additional opportunities for generating revenue by processing third party natural gas. In 2007, with the addition of Shell Tay River gas volumes and continued success along the Chungo Mississippian trend, net processing income was $19.8 million.
Kaybob District
The Kaybob District consists of land located in the Fox Creek region of Alberta and is divided into four areas. The Kaybob South Beaverhill Lake Unit 1 (35.6% working interest), Kaybob South Triassic Unit 1 (40.5% working interest), Kaybob South Triassic Unit 2 (26.8% working interest), andnon-unit lands (various working interests from gross overriding royalty to 100% working interest). We divested the Kaybob South Beaverhill Lake Unit #1 effective January 1, 2008.
We have a 17.8% working interest in the sour gas portion and a 20.4% working interest in the sweet gas portion of the plant. We also have various working interests in sweet gas gathering and compression facilities in the area. During 2007, our gross production from this district was 453 bbls/day of oil, 575 bbls/day of NGL and 11.0 mmcf/day of natural gas. We divested our 4.6% working interest in the Kaybob amalgamated plant when we divested our interest in the Beaverhill Lake Unit #1.
Alberta/British Columbia Plains District
Boundary Lake Area
We hold a 50% working interest in the Boundary Lake Gas Unit and a 34% and 19% interest in the Boundary Lake oil unit 1 and 2, respectively, in north-east British Columbia. Our natural gas production from this area is derived from five Belloy sour gas pools, and is processed at the nearby Boundary Lake processing plant. Our gross production from this area was 7.8 mmcf/day of natural gas and 1,528 bbls/day of crude oil and NGL during 2007.
Valhalla and Wapiti Area
We hold an approximate 30% interest in three Valhalla oil units, a 100% interest in the Valhallanon-unit waterflood wells and a 100% interest in the Wapiti property. Production is primarily from the Doe Creek and Cardium zones and consists of light crude oil, NGL and natural gas. Our gross production from these properties averaged 2,839 bbls/day of crude oil and NGL and 7.6 mmcf/day of natural gas in 2007. Our plans for this area in 2008 are to continue our horizontal injection well development program with six wells planned to improve waterflood conformance and arrest declining production in the main Doe Creek I pool.
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Kakwa Area
We hold an average 60% working interest in oil and gas processing facilities and associated oil and gas gathering systems in the Kakwa area. Our gross production from this area was 11.8 mmcf/day of natural gas, 524 bbls/day of NGL and 149 bbls/day of oil in 2007.
Lynx, Copton and Grande Cache Areas
We continue to focus on exploration in the Lynx/Copton/Grande Cache areas of western Alberta with the drilling and completing of 1.5 net discovery wells. During 2007, average gross production was 19 mmcf/day of natural gas. We plan to continue to develop these properties in 2008 to maintain our gross production at between 15 mmcf/day to 20 mmcf/day of natural gas.
Foothills West District
Caroline Area
We hold an 11% working interest in the 32,000 acre Caroline natural gas field located approximately 97 kilometres north-west of Calgary. The field has a high proportion of NGL and as a result the economics of this field are enhanced.
We also hold an 11% interest in the Caroline sour gas processing facility. The plant is presently running at 73% utilization based on design capacity and is processing approximately 78.6 mmcf/day of total plant sales gas and 16,500 mbbls/day of NGL. Husky gross production was 2,160 bbls/day of NGL and 5.7 mmcf/day of natural gas in 2007. Our plans for 2008 are to start up the newly installed low pressure steam recovery unit to displace approximately one third of our external power consumption.
Edson Area
We hold and operate an average 85% working interest in two gas processing facilities and associated gas gathering systems in the Edson area. These properties averaged gross production of 36.1 mmcf/day of natural gas and 1,670 bbls/day of NGL in 2007. The 2007 development program consisted of 44 gross development wells and we plan to drill 40 gas wells in 2008 to increase average production to 40 mmcf/day and improve drainage of the reservoir. Also, in 2008, we plan to install additional field and plant inlet booster compressors at both Ansell and Galloway.
Sikanni and Federal Areas
We hold interests in properties in the Sikanni and Federal areas of north-east British Columbia, which averaged gross production of 9.0 mmcf/day of natural gas from five wells in 2007. Our natural gas production flows through our gathering systems for processing at third party plants at Sikanni and McMahon. In March 2008, we will complete the tie-in of a discovery well in the Federal area, which is expected to add 9 mmcf/day of additional production starting in April 2008.
Graham Area
We hold a 40% working interest in lands in the Graham area of north-eastern British Columbia. Our gross production from this area in 2007 averaged 6.0 mmcf/day of natural gas. Production from the property is from one Halfway and seven Baldonnel pools. We also hold an interest in two 1,500 horsepower compressor stations and the non-operated Cypress gas plant. Plant capacity is 45 mmcf/day and the plant is currently operating at 75% capacity. We hold a 33.2% interest in the gas treating unit, 28.2% interest in the amine unit and 28% interest in the sulphur unit.
Grizzly Valley and Bullmoose Area
We hold a33-50% working interest in four wells in this new exploration area. We and one of our partners in the area have agreed to preliminary terms with a custom processor to construct a gathering system into the Grizzly Valley to transport production into Alberta for processing. The gathering system is expected to be completed by early 2010. Our total capacity in the system will be 30 mmcf/day. We are flowing natural gas production from the area in 2007 though interruptible capacity in the Duke system and averaged 3.9 mmcf/day of natural gas production from this area.
East Central Alberta
Red Deer and Hussar Districts
The core of the Red Deer and Hussar districts is between Calgary, Drumheller and Sylvan Lake. We operate 21 facilities with gas gathering systems in these districts. Our gross production from this area averaged 75.3 mmcf/day of natural gas and 2.1 mmbbls/day of crude oil and NGL in 2007. We intend to continue to develop the natural gas potential
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of these districts with infill, step out and exploratory wells to optimize gas recovery and develop new pools in order to operate the facilities at capacity. We are involved in coal bed methane development in this area, which had 510 wells drilled by year end 2007 and extensive facilities built. There were 460 wells tied-in by year-end that were producing a total of 56 mmcf/day (27 mmcf/day gross share) of natural gas. Our plans for 2008 include drilling 100 wells and we expect to reach gross production of 30 mmcf/day of natural gas.
Provost District
The centre of the Provost district is approximately 240 kilometres south-east of Edmonton. It is predominantly a medium crude oil area that averaged gross production of 14.1 mbbls/day of crude oil and 24.6 mmcf/day of natural gas in 2007. We intend to increase oil well drilling in many existing pools, focus on managing operating costs and improve oil recovery, as well as increase investment on natural gas exploration and development. There is significant competition in the area for land as well as infrastructure. We have a large land position and maintain close to a 100% working interest in most of our facilities. In 2008, we intend to continue to develop several of our 2005 to 2007 natural gas and oil discoveries.
Athabasca District
The Athabasca district extends approximately 175 kilometres north of Edmonton, and from the Alberta-Saskatchewan border in the east, to the Alberta foothills in the west. The area target is predominantly shallow gas, ranging from450-900 metres in the multi-zone Palaeozoic Mannville formation. The main producing areas are Athabasca, Craigend and Cold Lake. We operate 32 facilities with a pipeline system and an average working interest of 90% in the producing wells. We intend to continue developing this area with infill, step out and exploratory wells to optimize recovery and develop new pools in order to keep the facilities operating at capacity. In 2007 and into 2008, we are increasing our focus on exploration for higher netback oil opportunities. Our gross production from this area averaged 47.0 mmcf/day of natural gas and 490 bbls/day of crude oil in 2007.
Southern Alberta and Southern Saskatchewan
Southern Saskatchewan District
Husky is a prominent operator in southern Saskatchewan primarily producing medium gravity crude oil, with some natural gas and light crude oil. Our gross production from properties in this district averaged 21.7 mbbls/day of crude oil and 61.5 mmcf/day of natural gas during 2007.
We operate 32 oil batteries and 8 gas facilities in the southern Saskatchewan district. The oil pools in this area are exploited using pressure maintenance and waterflood recovery operations.
At the Shackleton/Lacadena Milk River shallow gas project, 93 wells were drilled and tied in 2007. The project was producing at a rate of 40.0 mmcf/day of natural gas at December 31, 2007 from a total of 540 wells. In 2008, we plan to drill between 120 and 140 additional step out and infill wells.
Southern Alberta District
Taber and Brooks are our two major centres in southern Alberta. We operate 27 oil facilities and 3 natural gas facilities with an average working interest of 95%. Oil production is mainly medium gravity crude with the majority of reserves being supported by waterfloods or active aquifers. Natural gas production is from a mixture of deep and shallow formations. At Warner, near Taber, we operate a recently implemented alkaline-polymer flood to increase recovery from the Cretaceous Mannville reservoir and we implemented an additional alkaline surfactant polymer flood at Crowsnest. Our gross production from this district averaged 8.0 mbbls/day of crude oil and 22.5 mmcf/day of natural gas during 2007.
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Oil Sands
Athabasca, Cold Lake and Peace River
Husky currently holds interests in 553,770 acres in the bitumen prone areas of Athabasca, Cold Lake and Peace River.
Tucker
At Tucker, an in-situ SAGD oil sands project located 30 kilometres northwest of Cold Lake, Alberta, Husky completed commissioning and achieved production from the first 32 well pairs. Initial production has been slower than anticipated largely due to the position of some wells relative to the water saturation zone of the reservoir. While optimization strategies are continuing on existing well pads, the drilling of eight new well pairs on Pad C is complete and a new D pad with well pairs placed in an optimized position in the reservoir has been planned. Production at the end of 2007 was 2,700 bbls/day.
Sunrise
Agreement was reached with BP Corporation North America Inc. (“BP”) to create an integrated North American oil sands business consisting of upstream and downstream assets based on Husky’s Sunrise holdings and BP’s Toledo, Ohio, USA refinery. The business consists of a 50/50 partnership to develop the Sunrise oil sands project contributed and operated by Husky and a 50/50 limited liability company for the Toledo refinery contributed and operated by BP.
During 2007, the front-end engineering design (“FEED”) was completed for the Sunrise in-situ SAGD oil sands project, located in the Athabasca region of northern Alberta. Site preparation, including clearing of development areas at the central plant site was started. Detailed engineering is expected to begin during the second quarter of 2008.
The Sunrise Project was approved by the Energy Resources Conservation Board (“ERCB”) in December of 2005. An amendment application was submitted in March of 2007, which outlines changes and optimizations resulting from ongoing depletion planning and front-end engineering design. Amendment approvals are expected from both the ERCB and Alberta Environment by the end of the second quarter of 2008. The project will proceed in phases with the first phase of 60 mbbls/day scheduled for first oil in 2012. Collaboration with various industry participants on regional infrastructure issues, including an access road and aerodrome, is underway.
Saleski/Caribou
At Saleski, we acquired oil sands leases totalling 2,560 acres in 2007. We now hold 241,760 acres in this area, which is located approximately 120 kilometres west of Fort McMurray, Alberta. In December 2006 we submitted an application to the AEUB and Alberta Environment applications for the first phase of an in-situ project for Caribou. We have responded to additional information requests and expect the regulatory approval in early 2008. A FEED study was completed during 2007.
At Caribou we completed the selection of 10 stratigraphic test wells and one water source well locations, which will be drilled during the remainder of the 2007/2008 winter drilling season. At Saleski we completed selection of 13 stratigraphic test well locations, which will also be drilled during the remainder of the 2007/2008 drilling season. In addition, development planning continued in respect of water source and disposal wells and the appropriate bitumen recovery technique for Saleski.
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Oil Sands Leases
Oil Sands | Gross | Net | Husky | |||||||||||||
General Location Name | Area | Acres | Acres | Operator | ||||||||||||
South Athabasca — overriding royalty | Athabasca | 35,601 | — | No | ||||||||||||
South Athabasca | Athabasca | 22,672 | 11,656 | Yes | ||||||||||||
Sunrise — In situ(1) | Athabasca | 64,034 | 64,034 | Yes | ||||||||||||
South Sunrise | Athabasca | 40,320 | 40,320 | Yes | ||||||||||||
Misthae (Drowned, Martin Hills W. & Spur) | Athabasca | 28,160 | 28,160 | Yes | ||||||||||||
Saleski | Athabasca | 241,760 | 241,760 | Yes | ||||||||||||
Hoole — overriding royalty | Athabasca | 47,040 | — | No | ||||||||||||
Beaverdam | Cold Lake | 11,520 | 11,520 | Yes | ||||||||||||
Caribou(2) | Cold Lake | 35,840 | 35,840 | Yes | ||||||||||||
Lobstick | Cold Lake | 37,120 | 37,120 | Yes | ||||||||||||
Tucker | Cold Lake | 10,080 | 10,080 | Yes | ||||||||||||
Panny (Senex & Welstead) | Peace River | 50,560 | 50,560 | Yes | ||||||||||||
Peace River (Cadotte Lake) | Peace River | 11,840 | 11,840 | Yes | ||||||||||||
Sawn Lake (Loon) | Peace River | 17,280 | 17,280 | Yes | ||||||||||||
653,827 | 560,170 | |||||||||||||||
Notes:
(1) | Included in the gross and net amounts are an additional 6,400 acres of petroleum and natural gas rights held as protection acreage for gas over bitumen issues. In 2003, the Alberta regulatory authority issued General Bulletin GB2003-28 that required natural gas wells within certain bitumen prone areas to be shut-in. The production of natural gas where natural gas reservoirs were believed to be in pressure contact with bitumen reserves was deemed to present an unacceptable risk to future in-situ bitumen production. Sunrise was formerly named Kearl. |
(2) | Husky also has the exclusive right to acquire an additional 65,280 acres in the Caribou area. |
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Northwest Territories
In the Northwest Territories we have a focused land position in the Central Mackenzie Valley consisting of four exploration licences (“EL”), EL 397, EL 423, EL 441 and EL 443. In addition, we have interests in several freehold blocks. During 2006, we announced the natural gas discovery of theStewart D-57 on the Tulita District Land Corporation Freehold Block (“TDL”)M-38 located within EL 397. Open hole testing from two intervals resulted in natural gas flows with a combined rate of 5 mmcf/day. In 2006 we drilled an appraisal well at Summit Creek on EL 397. The SummitCreek K-44 is located 1.4 kilometres north of the SummitCreek B-44 discovery well on EL 397. Preparation for the 2008 drilling program is currently underway. Two exploration wells are planned for the first half of 2008 on EL 423, which is located approximately 60 kilometres southeast of the StewartCreek D-57 and the SummitCreek B-44 discovery wells. We hold a 75% working interest in this play.
Offshore East Coast — Canada
Husky’s offshore East Coast exploration and development program is focused in the Jeanne d’Arc Basin on the Grand Banks offshore the coast of Newfoundland and Labrador, which contains the Hibernia, Terra Nova and White Rose oil fields. We hold ownership interests in the Terra Nova and White Rose oil fields as well as in a number of smaller undeveloped fields in the central part of the basin and also hold significant exploration acreage including five Significant Discovery Licences (“SDL”) on the Labrador shelf.
White Rose Oil Field
The White Rose oil field, which we operate, is located 354 kilometres off the coast of Newfoundland and Labrador approximately 48 kilometres east of the Hibernia oil field on the eastern section of the Jeanne d’Arc Basin. Husky’s interest in the existing White Rose oil field development is 72.5%.
In November 2005, first oil was achieved at White Rose. White Rose was the third oil field developed offshore Newfoundland and Labrador. During 2007, development drilling included one production well, one water injector and one gas injector. Following successful performance testing, we received approval to operate theSeaRose FPSOat a daily maximum of 140,000 bbls/day (101,500 bbls/day Husky interest), or 50 million barrels per year (36.25 mmbbls/year Husky interest). We transport White Rose crude oil to market with three chartered shuttle tankers.
During 2007, Husky successfully completed discussions with the Government of Newfoundland and Labrador on a framework agreement on fiscal terms for the White Rose satellite oil fields. Under the terms of the agreement, the province’s energy corporation will purchase a 5% equity stake in the White Rose expansion lands, which include identified pools at North Amethyst, South White Rose Extension and West White Rose. We intend to develop the expansion lands through a series of subsea tiebacks to theSeaRose FPSO. We will remain the project operator, and will retain a 68.875% working interest. The existing partnership and fiscal terms for the White Rose core field are unchanged. The fiscal terms for the satellite tiebacks also provide for a 6.5% price sensitive royalty to be paid after Tier 1 payout has been achieved and when West Texas Intermediate is above U.S. $50/bbl.
During September 2007, government and regulatory approval was received for the South White Rose Extension and in November 2007 we were awarded two new production licences covering the North Amethyst and South White Rose Extension portions of the field. Government and regulatory decisions on the development application for the North Amethyst subsea tieback are anticipated in early 2008. We also expect to file a development application for the West White Rose satellite tieback during 2008. A project team based in St. John’s, Newfoundland and Labrador continues to advance detailed engineering and design work for the satellite fields. Subject to appropriate government, regulatory and corporate approvals, we plan to commence development drilling at North Amethyst in the summer of 2008 with a first oil target date of late 2009.
During 2007, two delineation wells were drilled in the western and northern portions of the North Amethyst field. The results of theC-30 well and sidetrack, and theK-03 well are currently being evaluated.
We have and will continue to consider technical options for the development of natural gas in the Jeanne d’Arc Basin. We intend to proceed with technical screening of a short list of proposed solutions and review of high level cost estimates. In parallel and pending rig availability, delineation drilling will improve estimates of the resource base prior to the development phase.
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Terra Nova Oil Field
The Terra Nova oil field is located approximately 350 kilometres south-east of St. John’s, Newfoundland and Labrador in 91 to 100 metres of water. The Terra Nova oil field is divided into three distinct areas, known as the Graben, the East Flank and the Far East. Our current pooled interest in the Terra Nova field is 12.51%. This interest is subject to change, subsequent to a re-determination scheduled to occur on January 31, 2009. Production at Terra Nova commenced in January 2002. Husky’s gross share of production in 2007 from the Terra Nova field was 5.3 mmbbls or an average of 14.5 mbbls/day.
As at December 31, 2007, there were 14 development wells drilled in the Graben area, eight production wells, three water injection wells and three gas injection wells. In the East Flank area there were eleven development wells including six production wells and five water injection wells. There is one extended reach producer and an extended reach water injection well in the Far East Central area. Terra Nova completed the latest phase of the development drilling program in August 2007. Drilling operations are expected to resume in the 2010 to 2011 time period.
The Far East South I-66 delineation well completed drilling in February 2007. On January 31, 2008, the Canada-Newfoundland-Labrador-Offshore-Petroleum-Board (“CNLOPB”) issued its decision confirming the satisfaction of certain conditions approval for the Amended Development Plan relating to the well requirements and resource assessment. Pursuant to an agreement amongst the Terra Nova owners, re-determination will occur on the first anniversary of the satisfaction of the preceding conditions being January 31, 2009.
East Coast Exploration
We believe that the areas offshore the Canadian East Coast have exploration potential, and that our position there will provide growth opportunities for light crude oil and natural gas in the medium to long-term. We presently hold working interests ranging from 5.33% to 73.125% in 16 SDL areas in the Jeanne d’Arc Basin. We also hold interests ranging from 17.1% to 42.0% in six SDL areas on the Labrador Shelf, a region that could be significant, in the long-term, for natural gas reserves.
As of December 31, 2007, Husky held a working interest in 12 ELs in the Jeanne d’Arc Basin. Three of these licences (ELs 1067, 1045 & 1044) expired on January 15, 2008. Of the remaining nine ELs, we are the operator of seven and hold a 100% working interest in six and a 50% working interest in the remaining three.
In 2008, we will participate in our largest offshore seismic acquisition program to date, including the White Rose area and portions of ELs 1090 and 1091. Husky continues to evaluate drilling opportunities in the context of its full portfolio of East Coast land holdings.
On the Labrador Shelf, we are the operator of the Hekja natural gas discovery in which we hold a 42% interest. There are no active exploration licenses on the Labrador Shelf, however, the CNLOPB has announced that four blocks have been nominated for an August, 2008 land sale. In preparation for the sale the CNLOPB is conducting a regional environmental impact assessment for the Labrador Shelf area. We have an extensive grid of2-D seismic over of the Labrador Shelf and are currently evaluating the hydrocarbon potential of the region.
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East Coast
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International
Our international exploration and development programs are currently located in Southeast Asia and Greenland. In China, we have a 40% interest in one offshore oil producing operation at Wenchang and a 100% interest in six exploration blocks in the South China Sea and one in the East China Sea. In Indonesia, we have a 100% interest in the Madura Strait block production sharing contract (“PSC”) and a 100% interest in the Bawean II exploration block.
South China Sea
Wenchang
The Wenchang oil field is located in the western Pearl River Mouth Basin, approximately 400 kilometres south of Hong Kong and 100 kilometres east of Hainan Island. We hold a 40% working interest in the oil fields, which commenced production in July 2002. The Wenchang13-1 and13-2 oil fields are producing from 29 wells in 100 metres of water into a floating production, storage and offloading vessel stationed between fixed platforms located in the fields. The blended crude oil from the two fields averages approximately 35° API, similar to the benchmark Minas blend. At December 31, 2007, our gross proved reserves at Wenchang were 10.9 mmbbls of crude oil and NGL. Our gross production averaged 12.7 mbbls/day during 2007.
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Block 39/05
We executed a Production Sharing Contract (“PSC”) with China National Offshore Oil Corporation (“CNOOC”) for the 39/05 exploration block surrounding the Wenchang fields on October 1, 2001. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In January 2003, theQionghai 18-1-3 exploration type stratigraphic well on the block was plugged and abandoned without testing and in February 2003, theWenchang 8-1-1 exploration type stratigraphic well was plugged and abandoned without testing. We relinquished 25% of Block 39/05 in 2004 and an additional 25% in 2006. Husky has commenced Phase III, the final exploration phase of the PSC. In accordance with the contract we have committed to drilling a third exploration well expected to be commenced before the end of 2008. We currently hold 784,954 acres (2,973.6 sq. kms) in Block 39/05.
Block 23/15
We executed a PSC with CNOOC for the 23/15 exploration block on December 1, 2002. The contract area is located in the South China Sea north of Hainan Island, within 80 kilometres of the Weizhan oil fields. The work program required a single exploration well on the block within three years. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In 2003, we completed a 247,105 acres (1,000 sq. kms)3-D seismic survey shot over a portion of the block. Husky fulfilled its Phase I commitments on block 23/15 with the drilling ofWushi 17-1-1 in 2005, which encountered non-commercial oil. We have decided to proceed with Phase II of the PSC. We relinquished 25% of the 23/15 block prior to the 2005 Phase I expiry and have committed to drilling a second exploration well before the Phase II expiry on May 31, 2008. We currently hold 243,893 acres (987 sq. kms) in the 23/15 block.
Block 29/26
We executed a PSC with CNOOC for the 29/26 exploration block on October 1, 2004. The block is located in the South China Sea approximately 300 kilometres south east of Hong Kong and 65 kilometres south east of the Panyu gas discovery. The block covers an area of approximately 734,777 acres (2,973.6 sq. kms), after the 25% relinquishment at the end of Phase I in 2007. CNOOC has the right to participate in the development of any discoveries up to a 51% working interest. We completed a drilling program in 2006, with the drilling of theLiwan 3-1-1 natural gas discovery. The well location was chosen based on2-D seismic data and drilled to a total depth of 3,843 metres on a large structure with 14,826 acres of closure and encountered 56 metres of net natural gas pay on logs over four zones. This well was drilled in water 1,500 metres deep. In August 2006, we shot a 98,842 acre (400 sq. kms) seismic survey overLiwan 3-1-1 and the adjacent structures. In January 2007, we signed a 3 year contract with Seadrill Offshore AS for the deep water semi-submersible drilling rig, West Hercules. The West Hercules is currently under construction in South Korea and is scheduled for delivery in 2008. In preparation for the West Hercules, delineation drilling and further exploration drilling, we signed a contract with China Offshore Seismic Limited for the acquisition of 646,180 acres (2,615 sq. kms) of3-D seismic data in 2007. At year end 49,420 acres (200 sq. kms) remained to complete the program and this will be acquired in the second quarter of 2008. Following the delivery of the West Hercules rig in 2008, a four well delineation drilling program will commence. We also plan to conduct further exploration drilling on the block. In order to further accelerate theLiwan 3-1 development, a number of preliminary engineering studies were completed in late 2007 with the aim of conceptualizing facilities options to cover a range of potential production scenarios. These engineering studies included field development options, topsides facilities and preliminary pipeline routing. We also completed a desktop metocean study and awarded a contract for the field acquisition of new proprietary metocean data, which is anticipated to commence in early 2008 and take approximately two years.
Block 29/06
We executed a PSC with CNOOC for the29/06 exploration block on October 1, 2006. The block is located in the South China Sea immediately east and adjacent to block 29/26. The block is more than twice the size of Block 29/26, covering an area of approximately 2,289,382 acres (9,265 sq. kms). CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In the first exploration phase, we have committed to acquiring 179,148 acres (725 sq. kms) of3-D seismic in the second quarter of 2008 and drilling two exploration wells within three years.Block 29/06 seismic will be integrated with the seismic acquisition on Block 29/26, making the total area of3-D seismic approximately 825,314 acres (3,340 sq. kms).
Block 35/18 and 50/14
We executed two PSCs with CNOOC for the 35/18 and 50/14 exploration blocks on October 1, 2006. Both contract areas are located in shallow water in the South China Sea immediately west of Hainan Island adjacent to the Dong Fang
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and Ledong gas fields. The 35/18 block is approximately 1,104,312 acres (4,469 sq. kms) and the Block 50/14 is 775,168 acres (3,137 sq. kms). The work program requires us to drill a single exploration well on each block within three years. In addition, we committed to acquiring 123,550 acres (500 sq. kms) of3-D seismic on Block 35/18 in the first three years. We expect to commence the seismic program in the first quarter of 2008. CNOOC has the right to participate in development of any discoveries up to a 51% working interest.
East China Sea
Block 04/35
We executed a PSC with CNOOC for the 04/35 exploration block on December 1, 2003. The block is located in the East China Sea approximately 350 kilometres east of the city of Shanghai and covers an area of approximately 979,771 acres (3,965 sq. kms). The PSC requires the drilling of a single exploration well in the first exploration phase to a depth of 2,500 metres within three years and a minimum work commitment of U.S. $3 million. Technical evaluations of the hydrocarbon potential are complete and we expect to fulfill our Phase I drilling subject to drilling rig logistics. CNOOC has the right to participate in development of any discoveries up to a 51% working interest.
East Bawean II, Indonesia
We have executed a PSC with the Government of Indonesia for the East Bawean II block. The 1,051,433 acres (4,255 sq. kms) are located in the North East Java Basin approximately 200 kilometres north of the Madura Strait PSC where we are in the early development phase of the BD gas field. The acquisition of this block increases our total area in Indonesia to 1,742,093 acres (7,050 sq. kms). The PSC requires the acquisition of3-D seismic with a commitment of U.S. $7 million, and the drilling of two exploration wells with a commitment of U.S. $16 million, within the first three years of the contract. The acquisition of the 348,270-acre (1,410 sq. kms)3-D program was completed in December, 2007 and final processing is expected in May, 2008. Two exploration wells are planned for 2009.
Madura Strait, Indonesia
We have a 100% interest in approximately 690,412 acres (2,794 sq. kms) of the Madura Strait block, located offshore East Java south of Madura Island, Indonesia. There are two discovered natural gas fields on the block. The larger of these is the Madura BD field, which was granted commercial status and had a plan of development approved by the Indonesian state oil company in 1995. The field was to supply natural gas to a new proposed independent power plant. However, construction of the power plant did not proceed due to economic issues that occurred in Indonesia at that time and as a result the BD development was deferred. Current market conditions are favourable for the BD development and have allowed us to proceed with plans to supply gas to meet the demand of the East Java region. We now have gas sales contracts signed with three gas buyers, submitted an updated development plan and have been involved in negotiations with the Government of Indonesia to obtain an extension to the PSC. We expect to conclude these arrangements in 2008 and commence the front-end engineering design for the BD field development. Production is expected to come on stream approximately three to four years after all agreements have been approved by the Government of Indonesia.
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Greenland
During 2007, we were awarded three exploration blocks 120 kilometres offshore the west coast of Disko Island, Greenland. Block 5 is 2,505,154 acres (10,138 sq. kms) and requires a work program of U.S. $10.6 million. Block 7 is 2,700,615 acres (10,929 sq. kms) and requires a work program of U.S. $28 million. The work program includes the acquisition of 7,000 kilometres of2-D seismic and 1,000 sq. kilometres of3-D seismic. Both blocks are located in 500 metres of water. We are the operator and hold an interest of 87.5% in both blocks. The non-operated Block 6 is 3,265,000 acres (13,213 sq. kms) and we hold a 43.75% interest in this block. During 2007, we began an aerogravity and magnetic survey that will be resumed in the first half of 2008.
Shatirah, Libya
We have a non-operated interest in a small crude oil production operation in the Shatirah field, onshore Libya.
Distribution of Oil and Gas Production
Crude Oil and NGLs
Husky provides heavy crude oil feedstock to its upgrader and its asphalt refinery, which are located at Lloydminster Alberta/Saskatchewan. The combined dry crude feedstock requirements of the upgrader and asphalt refinery are equal to approximately 75% of our heavy crude oil production from the Lloydminster area. We also market heavy crude oil production directly to refiners located in the mid-west and eastern United States and Canada. We market our light and synthetic crude oil production to third party refiners in Canada, the United States and Asia. Natural gas liquids are sold to local petrochemical end users, retail and wholesale distributors and to refiners in North America.
We market third party volumes of light crude oil, heavy crude oil and NGLs in addition to our own production.
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Natural Gas
The following table shows the distribution of our gross average daily natural gas production for the years indicated:
Years ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(mmcf/day) | ||||||||||||
Sales to end users | ||||||||||||
United States | 338 | 335 | 357 | |||||||||
Canada | 208 | 231 | 212 | |||||||||
546 | 566 | 569 | ||||||||||
Sales to aggregators | 21 | 26 | 31 | |||||||||
Internal use(1) | 56 | 80 | 80 | |||||||||
623 | 672 | 680 | ||||||||||
Note:
(1) | Husky consumes natural gas for fuel at several of its facilities. |
We also market third party natural gas production in addition to our own production.
Delivery Commitments
The following table shows the future commitments to deliver natural gas from our reserves. Our proved developed reserves of natural gas in Western Canada are more than adequate to meet future delivery commitments.
Fixed Price | Market Price | |||||||||||
Bcf | $/mmbtu | Bcf | ||||||||||
2008 | 19 | 4.91 | 24 | |||||||||
2009 | 19 | 5.18 | 8 | |||||||||
2010 | 19 | 5.46 | 1 | |||||||||
2011 | 19 | 5.77 | — | |||||||||
2012 | 19 | 6.05 | — | |||||||||
2013 | 18 | 5.85 | — | |||||||||
2014 | 10 | 3.84 | — |
MIDSTREAM OPERATIONS
Overview
The midstream operations include:
• | Upgrading — the upgrading of heavy crude oil into synthetic light crude oil; | |
• | Infrastructure — pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent, and natural gas, extraction of NGL from natural gas, cogeneration of electrical and thermal energy; and | |
• | Commodity Marketing — the purchase and marketing of Husky’s and other producers’ crude oil, natural gas, NGLs, sulphur, petroleum coke and electrical power. |
Upgrading Operations
Husky owns and operates the Husky Lloydminster Upgrader (“Upgrader”), which is a heavy oil upgrading facility located in Lloydminster, Saskatchewan.
The Upgrader is designed to process blended heavy crude oil feedstock into high quality, low sulphur synthetic crude oil. Synthetic crude oil is used as refinery feedstock for the production of premium transportation fuels in Canada and the United States. In addition, the Upgrader recovers the diluent, which is blended with the heavy crude oil prior to pipeline transportation to reduce viscosity and facilitate its movement, and returns it to the field to be reused.
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Prior to the Upgrader, the market for heavy crude oil was either as feedstock for asphalt production or it was sold as blended heavy crude oil for feedstock for specific refineries designed to process or upgrade heavier crude. The Upgrader was commissioned in 1992 with an original design capacity of 46 mbbls/day of synthetic crude oil. Actual production is considerably higher than the original design rate capacity as a result of throughput modifications and improved reliability. In 2007, the Upgrader commenced production of off-road diesel for locomotive and other uses. The Upgrader’s current rated production capacity is 82 mbbls/day of synthetic crude oil, diluent and off-road diesel. Production at the Upgrader averaged 51.7 mbbls/day of synthetic crude oil and 9.4 mbbls/day of diluent in 2007. In addition to synthetic crude oil and recovered diluent, the Upgrader also produced, as by-products of its upgrading operations, approximately 279 lt/day of sulphur and 726 lt/day of petroleum coke during 2007. These products are sold in local and international markets. During 2007 the Upgrader underwent an extended turnaround, which lasted 49 days during May and June. In addition, during the third quarter of 2007, the debottleneck project was completed and resulted in increased throughput capacity from 77 mbbls/day to 82 mbbls/day of feedstock.
Infrastructure
Husky has been involved in the gathering, transporting and storage of heavy crude oil in the Lloydminster area since the early 1960s. Our crude oil pipeline systems include approximately 2,000 kilometres of pipeline and are capable of transporting in excess of 575 mbbls/day of blended heavy crude oil, diluent and synthetic crude oil. The pipeline systems transport blended heavy crude oil to Lloydminster, accessing markets through the Upgrader and our asphalt refinery in Lloydminster. Blended heavy crude oil from the field and synthetic crude oil from the upgrading operations are moved south to Hardisty, Alberta to a connection with the Enbridge Pipeline, the Kinder Morgan Express Pipeline and the Inter Pipeline Fund systems. The crude oil is transported to eastern and southern markets on these pipelines. Our crude oil pipeline systems also have feeder pipeline interconnections with the Cold Lake, the Echo Pipeline, the Gibsons Terminal, the Enbridge Athabasca Pipeline and the Talisman Chauvin Pipeline.
The following table shows the average daily pipeline throughput for the periods indicated:
Years ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(mbbls/day) | ||||||||||||
Combined pipeline throughput | 501 | 475 | 474 |
In recent years Husky has expanded and expects to further expand its heavy crude pipeline systems to capitalize on anticipated increases in heavy oil production from the Lloydminster and Cold Lake areas.
We consider the expansion and optimization of our pipeline systems in the Lloydminster area to be necessary to further our own development objectives in the area. As a result of recent expansion of the mainline pipeline systems in the area, competition for throughput volumes has increased.
We operate 16 heavy crude oil processing facilities located throughout the Lloydminster area. These facilities process Husky’s and other producers’ raw heavy crude oil from the field by removing sand, water and other impurities to produce clean dry heavy crude oil. The heavy crude oil is then blended with a diluent to lower both viscosity and density in order to meet pipeline specifications for transportation.
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HEAVY OIL PIPELINE SYSTEMS
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Cogeneration
We have a 50% interest in a 215 MW natural gas fired cogeneration facility at the site of the Lloydminster Upgrader. This cogeneration plant was commissioned in December 1999. Electricity produced at the facility is being sold to Saskatchewan Power Corporation under a 25 year power purchase agreement effective in 1999. Thermal energy (steam) is sold to the Upgrader.
We also have a 50% interest in a 90 MW natural gas fired cogeneration facility adjacent to Husky’s Rainbow Lake processing plant. The cogeneration plant produces electricity for the Alberta Power Pool and thermal energy (steam) for the Rainbow Lake processing plant. It provides power directly to the Alberta Power Pool under an agreement with the Alberta Transmission Administrator to provide additional electricity generating capacity and system stability for north-western Alberta. The power plant has the capability of being expanded to approximately 110 MW in total. We are the operator of the facility.
Natural Gas Storage Facilities
We have been operating a natural gas storage facility at Hussar, Alberta since April 2000. The facility has a working storage capacity of 17 bcf of natural gas. We also operate and have a 50% interest in a 6 bcf natural gas storage facility at East Cantaur near Swift Creek, Saskatchewan. We are continuing to evaluate additional storage opportunities within Western Canada.
Commodity Marketing
Husky is a marketer of both its own and third party production of crude oil, synthetic crude oil, NGL, natural gas and sulphur. We also market petroleum coke, a by-product from the Lloydminster Upgrader.
We supply feedstock to our Upgrader and asphalt refinery from our own and third party heavy oil production sourced from the Lloydminster and Cold Lake areas. We also sell blended heavy crude oil directly to refiners based in the United States and Canada. Our extensive infrastructure in the Lloydminster area supports its heavy crude oil refining and marketing operations.
We market light and medium crude oil and NGL sourced from our own production and third party production. Light crude oil is acquired for processing by third party refiners at Edmonton, Alberta and by our refinery at Prince George, British Columbia. We market the synthetic crude oil produced at our Upgrader in Lloydminster to refiners in Canada and the United States.
In July 2007, we acquired the Lima, Ohio refinery. The refinery has a crude charge capability of up to 160 mbbls/day. The crude oil feedstock for the Lima refinery is made up of U.S. domestic light and medium crude oil and foreign offshore light and medium crude oil primarily from West Africa.
We market natural gas sourced from our own production and third party production. We are currently committed to gas sales contracts with third parties, which in aggregate do not exceed amounts forecast to be deliverable from our reserves. Our contracts are with customers located in eastern Canada/north-eastern United States (31%), mid-west United States (29%), Western Canada (38%) and Northwest United States (2%). The natural gas volumes sales contracted are primarily at market prices (92%). At December 31, 2007, our natural gas sales contracts totalled 158 bcf over eight years. The natural gas is deliverable at the rate of 27% of the total 158 bcf in 2008, 17% in 2009, 12% in 2010, 11% from 2011 to 2014. Husky has acquired rights to firm pipeline capacity to transport the natural gas to most of these markets. We manage and trade natural gas in conjunction with our owned and operated natural gas storage facilities. We also contract additional natural gas storage under long-term arrangements. At December 31, 2007, we managed natural gas storage capacity of 37 bcf.
We have developed our commodity marketing operations to include the acquisition of third party volumes in order to increase volumes and enhance the value of our midstream assets. We plan to expand our marketing operations by continuing to increase marketing activities. We believe that this increase will generate synergies with the marketing of our own production volumes and the optimization of our assets. At December 31, 2007, we estimate commitments of approximately $1.4 billion in natural gas purchases, 95% of which is to be purchased in 2008. At December 31, 2007, we did not have any long-term commitments to purchase crude oil. Our purchases of crude oil primarily involve 30 day evergreen arrangements.
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DOWNSTREAM OPERATIONS
Canada
Overview
Our Canadian refined products operations include refining of light crude oil, manufacturing of fuel and industrial grade ethanol, manufacturing of asphalt products from heavy crude oil, acquisition by purchase and exchange of refined petroleum products. Our retail network provides a platform for substantial non-fuel related convenience product businesses.
Light oil refined products are produced at our refinery at Prince George, British Columbia and are also acquired from third party refiners and marketed through Husky and Mohawk branded retail and commercial petroleum outlets and through direct marketing to third party dealers and end users. Asphalt and residual products are produced at Husky’s asphalt refinery at Lloydminster and are marketed directly or through Husky’s eight emulsion plants, four of which are also asphalt terminals located throughout Western Canada.
Branded Petroleum Product Outlets and Commercial Distribution
Distribution
As of December 31, 2007, there were 505 independently operated Husky and Mohawk branded petroleum product outlets. These petroleum product outlets include service stations, travel centres and bulk distribution facilities located from the Ontario/Quebec border to the West Coast. The travel centre network is strategically located on major highways and serves the retail market and commercial transporters 24 hours per day, 365 days a year with quality products and full service Husky House restaurants. At most locations, the travel centre network also features the proprietary “Route Commander” cardlock system that enables commercial users to purchase products using a card system that will electronically process transactions and provide detailed billing, sales tax and other information. A variety of full and self serve retail locations under the Mohawk and Husky brand names serve urban and rural markets, while Husky and Mohawk bulk distributors offer direct sales to commercial and farm markets in Western Canada.
Our strategy in respect of our petroleum product outlets includes continuing to increase profits and sales through the strategic location of new outlets, the enhancement of ancillary non-fuel income streams, the modernization, automation and upgrading of existing petroleum product outlets, expanding customer loyalty programs and the sale of non-core locations. We also plan to enter into strategic alliances with third parties to sell various consumer products at Husky and Mohawk branded petroleum outlets in order to generate revenue and increase demand for other products and services provided at those outlets. We are pursuing acquisitions and joint venture opportunities to further enhance our existing distribution network.
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BRANDED PETROLEUM PRODUCT OUTLETS
Independent retailers or agents operate all Husky and Mohawk branded petroleum product outlets. Branded outlets feature varying services such as 24 hour service, convenience stores, service bays, car washes, Husky House full service family style restaurants, proprietary and co-branded quick serve restaurants, bank machines and alternate fuels such as propane and compressed natural gas. In addition to conventional gasolines, ethanol blended fuels branded as “Mother Nature’s Fuel” and additive enhanced “Diesel Max” are offered in all markets together with Chevron lubricants. Husky 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’s brands are promoted through the Husky Snowstars Program, various national and university athletic sponsorships as well as advertising designed to reach both national and regional audiences.
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The following table shows the number of Husky and Mohawk branded petroleum outlets by class of trade and by province as of December 31, 2007:
British | |||||||||||||||||||||||||||||
Columbia & | 2007 | 2006 | |||||||||||||||||||||||||||
Yukon | Alberta | Sask. | Manitoba | Ontario | Total | Total | |||||||||||||||||||||||
Retail Owned Outlets | |||||||||||||||||||||||||||||
Travel Centres | 10 | 8 | 4 | 2 | 12 | 36 | 36 | ||||||||||||||||||||||
Full Serve | 10 | 12 | 3 | 2 | 1 | 28 | 28 | ||||||||||||||||||||||
Full/Self Serve | 16 | 23 | 5 | 11 | 4 | 59 | 57 | ||||||||||||||||||||||
Self Serve | 18 | 19 | 1 | 1 | 2 | 41 | 40 | ||||||||||||||||||||||
Bulk Distributor | 1 | 9 | 3 | 1 | 1 | 15 | 15 | ||||||||||||||||||||||
Other Service Facilities Distributor | 3 | 8 | 0 | 1 | 1 | 13 | 13 | ||||||||||||||||||||||
58 | 79 | 16 | 18 | 21 | 192 | 189 | |||||||||||||||||||||||
Leased | |||||||||||||||||||||||||||||
Travel Centres | 1 | 0 | 0 | 0 | 0 | 1 | 1 | ||||||||||||||||||||||
Full Serve | 3 | 8 | 5 | 6 | 0 | 22 | 22 | ||||||||||||||||||||||
Full/Self Serve | 10 | 20 | 3 | 4 | 0 | 37 | 38 | ||||||||||||||||||||||
Self Serve | 35 | 25 | 0 | 1 | 0 | 61 | 60 | ||||||||||||||||||||||
Bulk Distributor | 2 | 0 | 0 | 0 | 0 | 2 | 2 | ||||||||||||||||||||||
Other Service Facilities Distributor | 1 | 3 | 0 | 2 | 2 | 8 | 8 | ||||||||||||||||||||||
52 | 56 | 8 | 13 | 2 | 131 | 131 | |||||||||||||||||||||||
Independent Retailers | |||||||||||||||||||||||||||||
Travel Centres | 1 | 2 | 0 | 0 | 4 | 7 | 7 | ||||||||||||||||||||||
Full Serve | 21 | 10 | 8 | 10 | 8 | 57 | 55 | ||||||||||||||||||||||
Full/Self Serve | 15 | 5 | 4 | 1 | 1 | 26 | 35 | ||||||||||||||||||||||
Self Serve | 28 | 44 | 4 | 2 | 0 | 78 | 77 | ||||||||||||||||||||||
Bulk Distributor | 2 | 4 | 2 | 0 | 0 | 8 | 6 | ||||||||||||||||||||||
Other Service Facilities Distributor | 1 | 2 | 0 | 0 | 3 | 6 | 5 | ||||||||||||||||||||||
68 | 67 | 18 | 13 | 16 | 182 | 185 | |||||||||||||||||||||||
Total | |||||||||||||||||||||||||||||
Travel Centres | 12 | 10 | 4 | 2 | 16 | 44 | 44 | ||||||||||||||||||||||
Full Serve | 34 | 30 | 16 | 18 | 9 | 107 | 105 | ||||||||||||||||||||||
Full/Self Serve | 41 | 48 | 12 | 16 | 5 | 122 | 130 | ||||||||||||||||||||||
Self Serve | 81 | 88 | 5 | 4 | 2 | 180 | 177 | ||||||||||||||||||||||
Bulk Distributor | 5 | 13 | 5 | 1 | 1 | 25 | 23 | ||||||||||||||||||||||
Other Service Facilities Distributor | 5 | 13 | 0 | 3 | 6 | 27 | 26 | ||||||||||||||||||||||
178 | 202 | 42 | 44 | 39 | 505 | 505 | |||||||||||||||||||||||
Cardlocks(1) | 26 | 21 | 4 | 5 | 24 | 80 | 73 | ||||||||||||||||||||||
Convenience Stores(1) | 161 | 178 | 34 | 39 | 32 | 444 | 445 | ||||||||||||||||||||||
Restaurants | 11 | 13 | 4 | 2 | 16 | 46 | 46 |
Note:
(1) | All of these are located at branded petroleum outlets. |
We also market refined petroleum products directly to various commercial markets, including independent dealers, national rail companies and major industrial and commercial customers in Western Canada and the north-western United States.
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The following table shows our average daily sales volumes of light refined petroleum products for the periods indicated:
Years ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(mbbls/day) | ||||||||||||
Gasoline | 27.8 | 27.5 | 28.3 | |||||||||
Diesel fuel | 27.4 | 26.4 | 26.5 | |||||||||
Liquefied petroleum gas | 0.9 | 0.9 | 0.9 | |||||||||
56.1 | 54.8 | 55.7 | ||||||||||
Prince George Refinery
The Prince George refinery production is equal to approximately 22% of our total refined product supply requirements and is the source of our lowest cost refined products. The refinery produces all grades of unleaded gasoline, seasonal diesel fuels, a mixed propane and butane stream, and heavy oil products.
Lloydminster Asphalt Refinery
Our Lloydminster refinery processes heavy crude into asphalt products used in road construction and maintenance, manufactured building products, locomotive blendstock and specialty oil field products. The refinery has a throughput capacity of 28,000 barrels per day of heavy crude oil. It also produces a distillate stream used by the Upgrader, and a condensate stream used to blend with heavy oil production.
Ethanol Manufacturing
In September 2006, we commissioned an ethanol facility in Lloydminster, Saskatchewan. This plant has an annual capacity of 130 million litres. In December 2007, the Minnedosa, Manitoba ethanol plant was commissioned also with an annual capacity of 130 million litres.
Our ethanol production supports our “Mother Nature’s Fuel” ethanol-blended gasoline marketing program. When added to gasoline, ethanol improves fuel combustion, raises octane levels, prevents fuel line freezing and reduces carbon monoxide emissions, ozone precursors and net emissions of greenhouse gases. Environment Canada has designated ethanol-blended gasoline as an “Environmental Choice” product.
We continue to position our Refined Products business segment as the leader in ethanol blended fuels in Western Canada.
Other Supply Arrangements
In addition to the refined petroleum products supplied by the Prince George refinery, we have rack based pricing purchase agreements for refined products with all major Canadian refiners. During 2007, we purchased approximately 33.6 mbbls/day of refined petroleum products from refiners and acquired approximately 9.1 mbbls/day of refined petroleum products pursuant to exchange agreements with third party refiners. During 2007, we also delivered an average of 13.6 mbbls/day of crude oil to be refined under a processing agreement by another refiner, yielding approximately 12.4 mbbls/day of refined petroleum products.
Asphalt Products
We produce asphalt and residual products at our 28 mbbls/day asphalt refinery at Lloydminster and market these products to customers across Western Canada and the north-western and Midwestern United States.
We have 38% of the market for paving asphalt sold in Western Canada. Our Pounder Emulsions division has a 50% market share in Western Canada for road application emulsion products. Additional non-asphalt based road maintenance products are marketed and distributed through Western Road Management, a division of Husky. We have increased sales to the United States and Eastern Canada, with 41% of production in 2007 exported to the United States and products shipped as far as Texas, Florida and New Brunswick.
We sell in excess of 5 mmbbls of asphalt cements per year. In addition, we produce and sell straight run gasoline, bulk distillates, and residuals. The bulk distillates are hydrogen deficient and are transferred directly to the Upgrader and then
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treated for blending into the Husky Synthetic Blend stream. The straight run gasoline stream is removed and re-circulated into the heavy oil pipeline network as pipeline diluent. Residuals are a blend of medium and light distillate and gas oil streams, which we sell directly to customers or further process at the Upgrader into off-road diesel.
Our asphalt distribution network consists of four emulsion/asphalt terminals located at Kamloops, British Columbia; Lethbridge, Alberta; Yorkton, Saskatchewan; and Winnipeg, Manitoba and four emulsion plants located at Edmonton, Alberta; Watson Lake, Yukon; Lloydminster and Saskatoon, Saskatchewan. We also use an independently operated terminal at Langley, British Columbia.
All of our asphalt requirements are supplied by our Lloydminster, Alberta asphalt refinery. The refinery had an original design rate throughput capacity of 25 mbbls/day. Debottleneck modifications have allowed us to increase that to 28 mbbls/day. The crude oil feedstock for the Lloydminster refinery is supplied through our pipeline systems from the supply of heavy crude oil in the region, including our heavy crude oil.
The following table shows our average daily sales volumes of products produced at the Lloydminster refinery, for the years indicated:
Years ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(mbbls/day) | ||||||||||||
Asphalt | 14.0 | 14.0 | 13.8 | |||||||||
Residual and other | 7.8 | 9.4 | 8.7 | |||||||||
21.8 | 23.4 | 22.5 | ||||||||||
Refinery throughput averaged 25.3 mbbls/day of blended heavy crude oil feedstock during 2007.
Due to the seasonal demand for asphalt products most asphalt refineries typically operate at full capacity only during the normal paving season in Canada and the northern United States. We have implemented various plans to increase refinery throughput during the other months of the year, such as producing low sulphur diesel, entering into custom processing arrangements and developing other U.S. and international markets for asphalt products. This allows us to run at or near full capacity year round.
Our strategy with respect to our asphalt marketing business is to increase sales volumes by increasing asphalt supply and developing new product streams, to enhance margins by soliciting industry for Husky ideal specifications, to minimize costs and expand our income base through new products and new markets and to pursue mergers, acquisitions, brokering and processing opportunities within our niche markets.
In 2008, we will direct our efforts to identifying acquisition, merger, brokering, terminalling, and processing opportunities. In addition, we expect to increase residual sales relative to diluents and bulk distillates to enhance margins, concentrate on sales of higher quality products with larger margins, develop new products and improve existing products.
United States
Refining and Marketing
Acquisition of the Lima Refining Company was closed on July 3, 2007. The Lima refinery has an atmospheric crude distillation capacity of 146 mbbls per calendar day (160 mbbls per stream day). The refinery is located in Ohio between Toledo and Dayton and currently processes primarily light sweet crude oil feedstock sourced from the United States and Africa. The refinery produces gasoline, gasoline blend stocks, diesel, jet fuel, petrochemical feedstocks and other by-products. The feedstock is received via the Mid-Valley and Marathon pipelines and the refined products are transported via the Buckeye and Inland pipeline systems and by rail car to primary markets in Ohio, Illinois, Indiana and southern Michigan.
The acquisition was effective July 1, 2007 and during the six months ended December 31, 2007 crude oil feedstock throughput averaged 135 mbbls/day and other feedstock averaged 9 mbbls/day. Production of gasoline averaged 82 mbbls/day, middle distillates averaged 47 mbbls/day and other fuel and feedstock averaged 16 mbbls/day.
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HUMAN RESOURCES
The number of employees in each business segment was as follows:
December 31, | ||||||||
2007 | 2006 | |||||||
Upstream | 2,510 | 2,357 | ||||||
Midstream | 389 | 375 | ||||||
Refined Products | 840 | 480 | ||||||
Corporate | 403 | 358 | ||||||
4,142 | 3,570 | |||||||
DIVIDENDS
The following table shows the aggregate amount of the cash dividends declared per common share of the Company and paid in respect of its last three years ended December 31:
2007 | 2006 | 2005 | ||||||||||
Cash dividends declared per common share | $ | 1.33 | $ | 0.75 | $ | 0.825 |
Dividend Policy and Restrictions
The Board of Directors of Husky has established a dividend policy that pays quarterly dividends. The dividend policy was reviewed in April 2005 and increased to $0.07 ($0.28 annually) per common share and again in October 2005 when it was increased to $0.125 ($0.50 annually) per common share. The dividend policy was reviewed in July 2006 and was increased to $0.25 ($1.00 annually) per common share and again in October 2007 when it was increased to $0.33 ($1.32 annually). The Board declared special cash dividends in the amount of $0.50 per common share in July 2003 and $0.27 per common share in November 2004. In October 2005, the Board declared a special dividend of $0.50 per common share. In February 2007, the Board declared a special dividend of $0.25 per common share. Husky’s dividend policy will continue to be reviewed and there can be no assurance that further dividends will be declared.
The declaration and payment of dividends will be at the discretion of the Board, which will consider earnings, capital requirements and financial condition of Husky, the satisfaction of the applicable solvency test in Husky’s governing corporate statute, theBusiness Corporations Act(Alberta), and other relevant factors.
DESCRIPTION OF CAPITAL STRUCTURE
Common Shares
Husky is authorized to issue an unlimited number of common shares. Holders of common shares are entitled to one vote per share at meetings of shareholders of Husky, to receive such dividends as declared by the Board of Directors on the common shares and to receive pro-rata the remaining property and assets of Husky upon its dissolution or winding up, subject to any rights having priority over the common shares.
Preferred Shares
Husky is authorized to issue an unlimited number of preferred shares. Holders of preferred shares shall not be entitled to vote at meetings of Husky, are entitled to receive such dividends as and when declared by the Board of Directors in priority to common shares and shall be entitled to receive pro-rata in priority to holders of common shares the remaining property and assets of Husky upon its dissolution or winding up. There are no preferred shares currently outstanding.
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Credit Ratings Summary
Rating | Last Review | Last Rating Change | ||||
Moody’s: | ||||||
Outlook | Stable | May 4, 2007 | — | |||
Senior Unsecured Debt | Baa2 | May 4, 2007 | April 25, 2001 | |||
Capital Securities | Ba1 | May 4, 2007 | April 25, 2001 | |||
Standard and Poor’s: | ||||||
Outlook | Stable | March 9, 2007 | July 27, 2006 | |||
Senior Unsecured Debt | BBB+ | March 9, 2007 | July 27, 2006 | |||
Capital Securities | BBB− | March 9, 2007 | July 27, 2006 | |||
Dominion Bond Rating Service: | ||||||
Under Review | ||||||
Trend | Positive | November 28, 2007 | — | |||
Senior Unsecured Debt | BBB(high) | November 28, 2007 | — | |||
Capital Securities | BBB | November 28, 2007 | — |
Credit ratings are intended to provide investors with an independent measure of credit quality of any issue of securities. The credit ratings accorded to Husky’s securities by the rating agencies are not recommendations to purchase, hold or sell the securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.
Moody’s
Moody’s credit rating system ranges from Aaa (highest) to C (lowest). Debt securities rated within the Baa category are considered medium grade debts; they are neither highly protected nor poorly secured. Interest payments and principal security appears to be adequate at the time of the rating however they are subject to potential adverse circumstances over time. As a result these debt securities possess some speculative characteristics. The addition of a 1, 2 or 3 modifier indicates an additional relative standing within the general rating classification. The addition of the modifier 1 indicates the debt is positioned in the top one third of the general rating classification, 2 indicates the mid one third and 3 indicates the bottom one third.
Standard and Poor’s
Standard and Poor’s credit rating system ranges from AAA (highest) to D (lowest). Debt securities rated within the BBB category are considered to possess adequate protection parameters. However, they could potentially change subject to adverse economic conditions or other circumstances that may result in reduced capacity of the debtor to continue to meet principal and interest payments. As a result these debt securities possess some speculative characteristics. The addition of the modifier + or − indicates the debt is positioned above (+) or below (−) the mid range of the general category.
Dominion Bond Rating Service
Dominion Bond Rating Service’s credit rating system ranges from AAA (highest) to D (lowest). Debt securities rated within the BBB category are considered to be of adequate credit quality. Protection of interest and principal is considered acceptable, but the debtor is susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of the debtor and its rated debt. The addition of the high or low modifier denotes that the rating is either above or below the mid range or the general rating category.
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MARKET FOR SECURITIES
Husky’s common shares are listed and posted for trading on the Toronto Stock Exchange under the trading symbol “HSE”.
The following table discloses the trading price range(1) and volume of Husky’s common shares traded on the Toronto Stock Exchange during Husky’s financial year ended December 31, 2007:
High | Low | Volume | ||||||||||
(000’s) | ||||||||||||
January | 39.30 | 35.40 | 26,844 | |||||||||
February | 39.25 | 37.26 | 27,193 | |||||||||
March | 40.95 | 35.83 | 21,468 | |||||||||
April | 42.97 | 40.11 | 16,038 | |||||||||
May | 45.44 | 42.00 | 21,213 | |||||||||
June | 46.65 | 41.92 | 21,989 | |||||||||
July | 45.35 | 40.13 | 17,313 | |||||||||
August | 42.80 | 35.01 | 23,990 | |||||||||
September | 42.75 | 38.16 | 16,926 | |||||||||
October | 44.28 | 40.18 | 30,095 | |||||||||
November | 44.35 | 38.75 | 26,817 | |||||||||
December | 44.77 | 39.03 | 18,642 |
Note:
(1) | Share prices adjusted to reflect a two for one share split effective July 9, 2007. |
DIRECTORS AND OFFICERS
The following are the names and residences of the officers of Husky as of the date of this Annual Information Form, their positions and offices with Husky and their principal occupations during the past five years. For information in respect of Husky’s directors, reference is made to the information contained in the section entitled “Election of Directors” at pages 5 through 8 inclusive of Husky’s Management Information Circular dated March 10, 2008, which is incorporated by reference in this Annual Information Form.
Officers
Name and Residence | Office or Position | Principal Occupation During Past 5 Years | ||
LAU, JOHN C.S. Calgary, Alberta, Canada | President & Chief Executive Officer and Director | President & Chief Executive Officer of Husky Energy Inc. since August 2000. | ||
INGRAM, DONALD R. Calgary, Alberta, Canada | Senior Vice President, Midstream & Refined Products | Senior Vice President, Midstream and Refined Products of Husky since August 2000. | ||
PEABODY, ROBERT J. Calgary, Alberta, Canada | Chief Operating Officer, Operations & Refining | Chief Operating Officer, Operations and Refining of Husky since January 2006. Prior to joining Husky, Mr. Peabody held the following positions with British Petroleum: Director Innovence Separation & Initial Public Offering Project from 2005 to 2006, President of Global Polymers, Chemicals from 2004 to 2005, Vice President, Polyester and Aromatics Americas from 2002 to 2004 and Vice President, BP Group Strategy & Planning from 1991 to 2001. | ||
GIRGULIS, JAMES D. Calgary, Alberta, Canada | Vice President, Legal & Corporate Secretary | Vice President, Legal & Corporate Secretary of Husky since August 2000. |
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As at February 29, 2008, the directors and officers of Husky, as a group, owned or controlled or directed, directly or indirectly, 360,699 common shares of Husky representing less than 1% of the issued and outstanding common shares.
Conflicts of Interest
Certain officers and directors of Husky are also officersand/or directors of other companies engaged in the oil and gas business generally and which, in certain cases, own interests in oil and gas properties in which Husky holds or may in future hold an interest. As a result, situations arise where the interests of such directors and officers conflict with their interests as directors and officers of other companies. In the case of the directors the resolution of such conflicts is governed by applicable corporate laws which require that directors act honestly, in good faith and with a view to the best interests of Husky and, in respect of theBusiness Corporations Act(Alberta), Husky’s governing statute, that directors declare, and refrain from voting on, any matter in which a director may have a conflict of interest.
Corporate Cease Trade Orders or Bankruptcies
None of those persons who are directors or officers of Husky is or has been within the past ten years, a director, chief executive officer or chief financial officer of any company, including Husky (and any personal holding companies), that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, for a period of more than 30 consecutive days, or after such persons ceased to be a director, chief executive officer or chief financial officer of the company was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, for a period of more than 30 consecutive days, which resulted from an event that occurred while acting in such capacity.
In addition, none of those persons who are directors or executive officers of Husky is, or has been within the past ten years, a director or executive officer of any company, including Husky, that while such person was acting in that capacity, or within a year of that person ceasing to act in that capacity became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manger or trustee appointed to hold its assets, other than Eva Kwok who was a director of Air Canada in 2003 at the time it became subject to creditor protection under theCompanies Creditors Arrangement Act(Canada). In addition, Holger Kluge and Frank Sixt were directors until April 12, 2002, of vLinx Inc., a private Canadian company which was petitioned into bankruptcy on April 15, 2002. vLinx Inc. developed technology and software to facilitate international trade. Mr. Fok acted as a non-executive director of Peregrine Investments Holdings Limited (an investment bank) which was put into compulsory liquidation on March 18, 1998.
Individual Penalties, Sanctions or Bankruptcies
None of the persons who are directors or officers of Husky (or any personal holding companies) have, within the past ten years made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold his assets. None of the persons who are directors or officers of the Company (or any personal holding companies) have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.
AUDIT COMMITTEE
The members of Husky’s Audit Committee are R.D. Fullerton (Chair), M.J.G. Glynn and W. Shurniak. Each of the members of the Company’s Audit Committee (the “Committee”) are independent in that each member does not have a direct or indirect material relationship with the Company. Multilateral Instrument52-110 — Audit Committees provides that a material relationship is a relationship which could, in the view of the board of directors of Husky (the “Board”), reasonably interfere with the exercise of a member’s independent judgment.
The Committee’s Charter provides that the Committee is to be comprised of at least three (3) members of the Board, all of whom shall be independent and meet the financial literacy requirements of applicable laws and regulations. Each member of the Committee is financially literate in that each has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Company’s financial statements.
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The education and experience of each Audit Committee member that is relevant to the performance of his responsibilities as an Audit Committee member is as follows.
R.D. Fullerton (Chair) — Before his retirement Mr. Fullerton served as Chief Executive Officer of CIBC and also served as a directorand/or an Audit Committee member of 16 major domestic and international public companies as well as director of a number of affiliates of CIBC.
M.J.G. Glynn — Mr. Glynn was a director and President and Chief Executive Officer of HSBC Bank USA N.A. from 2000 until his recent retirement in 2006.
W. Shurniak — Mr. Shurniak is a non-executive director of Hutchison Whampoa Limited and a director and Chairman of Northern Gas Networks Limited (a distributor of natural gas in Northern England), a private company.
Husky’s Audit Committee Charter is attached hereto as Schedule “A.”
External Auditor Service Fees
The following table provides information about the fees billed to the Company for professional services rendered by KPMG LLP, the Company’s external auditor, during fiscal years indicated:
Aggregate fees | ||||||||
billed by the | ||||||||
External Auditor | ||||||||
2007 | 2006 | |||||||
($ thousands) | ||||||||
Audit fees | 1,964 | 1,853 | ||||||
Audit-related fees | 154 | 109 | ||||||
Tax fees | 77 | 73 | ||||||
All other fees | — | — | ||||||
2,195 | 2,035 | |||||||
Audit Fees. Audit fees consist of fees for the audit of the Company’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings, including the Sarbanes-Oxley Act of 2002.
Audit-Related Fees. Audit-related services included attest services not required by statute or regulation and services with respect to acquisitions and dispositions.
Tax Fees. Tax fees included tax planning and various taxation matters.
All Other Fees. Other services provided by the Company’s external auditor, other than audit, audit-related and tax services.
The audit fees disclosed in the table above reflect amounts billed in the period indicated rather than the period of the audit.
The Company’s Audit Committee has the sole authority to review in advance, and grant any appropriate pre-approvals, of all non-audit services to be provided by the independent auditors and to approve fees, in connection therewith. The Audit Committee approved all of the audit-related, tax and other services provided by KPMG LLP in 2007.
LEGAL PROCEEDINGS
The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these or other matters or amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position, results of operations or liquidity.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
None of the Company’s directors, executive officers or persons or companies that beneficially own or control or direct, directly or indirectly, more than 10% of Husky’s common shares, or their associates and affiliates, had any material interest, direct or indirect, in any transaction with the Company within the three most recently completed financial years
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or during the current financial year that has materially affected or would reasonably be expected to materially affect the Company except as follows.
In late 2007, TransAlta Power, L.P. was acquired by an indirect subsidiary of Cheung Kong Infrastructure Holdings Limited, which is majority owned by Hutchison Whampoa Limited, which owns 100% of U.F. Investments (Barbados) Ltd. a 34.58% shareholder in Husky. TransAlta Power L.P. is a 49.99% owner of TransAlta Cogeneration, L.P. our partner in the Meridian Cogeneration plant in Lloydminster, Saskatchewan. We sell natural gas to the Meridian Cogeneration plant and other cogeneration plants owned by TransAlta Power L.P. In 2007, we sold $104 million of natural gas to TransAlta Power L.P.
The Company entered into a management agreement effective July 15, 2004 with Western Canadian Place Ltd. for general management of Western Canadian Place Ltd.’s leasehold interest in office space at 635 — 8th Avenue S.W., Calgary, Alberta. Western Canadian Place Ltd. is indirectly controlled by the Company’s principal shareholders. The Company’s President & Chief Executive Officer is also a director and officer of Western Canadian Place Ltd. The Vice President, Special Projects of the Company’s subsidiary, Husky Oil Operations Limited, is also a director and officer of Western Canadian Place Ltd. The Company was paid fees of $99,715 in 2006 and $129,547 in 2005 for providing such management services. This agreement was terminated effective August 31, 2006.
TRANSFER AGENT AND REGISTRARS
Husky’s transfer agent and registrar is Computershare Trust Company of Canada. In the United States, the transfer agent and registrar is Computershare Trust Company, Inc. The registers for transfers of the Company’s common shares are maintained by Computershare Trust Company of Canada at its principal offices in the cities of Calgary and Toronto. Queries should be directed to Computershare Trust Company at 1-888-267-6555 (toll free in North America).
MATERIAL CONTRACTS
The only material contract the Company entered into during the last completed financial year was the Project Agreement dated December 5, 2007, with BP Corporation North America Inc. See “Three Year History of Husky — 2007” in this AIF for particulars of this agreement.
INTERESTS OF EXPERTS
Certain information relating to the Company’s reserves included in this Annual Information Form has been calculated by the Company and audited and opined upon as of December 31, 2007 by McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum engineering consultants retained by Husky, and has been so included in reliance on the opinion and analysis of McDaniel, given upon the authority of said firm as experts in reserve engineering. The partners of McDaniel as a group beneficially own, directly or indirectly, less than 1% of the Company’s securities of any class.
ADDITIONAL INFORMATION
Additional information, including directors’ and officers’ remuneration, principal shareholders of Husky’s common shares and a description of options to purchase common shares is contained in Husky’s Management Information Circular dated March XX, 2008, prepared in connection with the annual and special meeting of shareholders to be held on April 21, 2008.
Additional financial information is provided in Husky’s Consolidated Financial Statements and Management’s Discussion and Analysis for the most recently completed fiscal year ended December 31, 2007, contained in Husky’s 2007 Annual Report.
Additional information relating to Husky Energy Inc. is available on SEDAR atwww.sedar.com.
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ABBREVIATIONS AND GLOSSARY OF TERMS
As used in this Annual Information Form, the following terms have the meanings indicated:
Units of Measure
bbl | — barrel | |
bbls | — barrels | |
mbbls | — thousand barrels | |
mmbbls | — million barrels | |
bbls/day | — barrels per calendar day | |
mbbls/day | — thousand barrels per calendar day | |
boe | — barrels of oil equivalent | |
boe/day | — barrels of oil equivalent per calendar day | |
mcf | — thousand cubic feet | |
mmcf | — million cubic feet | |
bcf | — billion cubic feet | |
mmcf/day | — million cubic feet per calendar day | |
mcfge | — thousand cubic feet of gas equivalent | |
lt | — long ton | |
mlt | — thousand long tons | |
lt/day | — long tons per calendar day | |
mlt/day | — thousand long tons per calendar day | |
mmbtu | — million British thermal units | |
Kms | — kilometres | |
MW | — megawatts | |
Acronyms | ||
API | — American Petroleum Institute | |
CNOOC | — Chinese National Offshore Oil Company | |
COGEH | — Canadian Oil and Gas Evaluation Handbook | |
EIA | — Energy Information Administration | |
EL | — Exploration Licence | |
ERCB | — Energy Resources Conservation Board | |
FAS | — Financial Accounting Statement | |
FASB | — Financial Accounting Standards Board | |
FPSO | — Floating production, storage and offloading vessel | |
LLB | — Lloydminster Blend | |
NGL | — Natural gas liquids | |
NWT | — Northwest Territories | |
NYMEX | — New York Mercantile Exchange | |
OPEC | — Organization of Petroleum Exporting Countries | |
PSC | — Production Sharing Contract | |
SAGD | — Steam assisted gravity drainage | |
SDL | — Significant Discovery License | |
SEC | — Securities and Exchange Commission of the United States | |
SEDAR | — System for Electronic Document Analysis and Retrieval | |
WCSB | — Western Canada Sedimentary Basin | |
WTI | — West Texas Intermediate crude oil |
API° gravity
Measure of oil density or specific gravity used in the petroleum industry. The American Petroleum Institute (API) scale expresses density such that the greater the density of the petroleum, the lower the degree of API gravity.
Barrel
A unit of volume equal to 42 U.S. gallons.
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Bitumen
A highly viscous oil which is too thick to flow in its native state, and which cannot be produced without altering its viscosity. The density of bitumen is generally less than 10 degrees API.
Bulk Terminal
A facility used primarily for the storageand/or marketing of petroleum products.
Coalbed Methane
The primary energy source of natural gas is methane (CH(4)). Coal bed methane is methane found and recovered from the coal bed seams. The methane is normally trapped in the coal by water that is under pressure. When the water is removed the methane is released.
Cold Production
A non-thermal production process for heavy oil in unconsolidated sand formations. During the cold production process heavy oil and sand are produced simultaneously through the use of progressive cavity pumps, which produce high pressure in the reservoir.
Debottleneck
To remove restrictions thus improving flow rates and productive capacity.
Delineation well
A well in close proximity to an oil or gas well that helps determine the areal extent of the reservoir.
Developed area
A drainage unit having a well completed thereon capable of producing oil or gas in paying quantities.
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 to improve the transmissibility of the oil through a pipeline.
Dry and abandoned well
A well found to be incapable of producing oil or gas in sufficient quantities to justify completion as a producing oil or gas well.
Enhanced recovery
The increased recovery from a crude oil pool achieved by artificial means or by the application of energy extrinsic to the pool, which artificial means or application includes pressuring, cycling, pressure maintenance or injection to the pool of a substance or form of energy but does not include the injection in a well of a substance or form of energy for the sole purpose of aiding in the lifting of fluids in the well, or stimulation of the reservoir at or near the well by mechanical, chemical, thermal or explosive means.
Exploration licence
A licence with respect to the Canadian offshore or the Northwest or Yukon Territories conferring the right to explore for, and the exclusive right to drill and test for, 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.
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Exploratory well
A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well as those items are defined herein.
Field
An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural featureand/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.
Gathering System
Pipeline system and associated facilities used to gather natural gas or crude oil from various wells and deliver it to a central point where it can be moved from there by a single pipeline to a processing facility or sales point.
Horizontal drilling
Drilling horizontally rather than vertically through a reservoir, thereby exposing more of the well to the reservoir and increasing production.
Hydrogen sulphide
A poisonous gas which is colourless and heavier than air and is found in sour gas.
Infill Well
A well drilled on an irregular pattern disregarding normal spacing requirements. These wells are drilled to produce from parts of a reservoir that would otherwise not be recovered through existing wells drilled in accordance with normal spacing.
Liquefied petroleum gas
Liquefied propanes and butanes, separately or in mixtures.
Metocean data
Meteorological and oceanographic data used for, among other things, the design of marine structures.
Miscible Flood
An enhanced recovery method which requires that three fluids exist in the reservoir: the mobile oil to be recovered, a displacing fluid (NGL) injected to move as a bank behind the oil, and a fluid injected to propel the displacing fluid (chase gas) through the reservoir.
Multiple completion well
A well producing from two or more formations by means of separate tubing strings run inside the casing, each of which carry hydrocarbons from a separate and distinct producing formation.
Natural gas liquids
Those hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants, or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butanes and condensate, or a combination thereof.
Oil Battery
An accessible area to accommodate separators, treaters, storage tanks and other equipment necessary to process and store crude oil and other fluids prior to transportation.
Oil Sands
Sands and other rock materials which contain crude bitumen and includes all other mineral substances in association therewith.
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Overriding royalty interests
An interest acquired or withheld in the oil and gas produced (or the proceeds from the sale of such oil and gas), received free and clear of all costs of development, operation, or maintenance and in addition to the usual landowner’s royalty reserved to the lessor in an oil and gas lease.
Primary recovery
The oil and gas recovered by any method that may be employed to produce the oil or gas through a single well bore. The fluid enters the well bore by the action of native reservoir energy or gravity.
Production Sharing Contract
A contract for the development of resources under which the contractor’s costs (investment) are recoverable each year out of the production but there is a maximum amount of production which can be applied to the cost recovery in any year. This annual allocation of production is referred to as cost oil, the remainder is referred to as profit oil and is divided in accordance with the contract between the contractor and the host government.
Raw gas
Gas as produced from a well before the separation therefrom of liquefiable hydrocarbons or other substances contained therein.
Secondary recovery
Oil or gas recovered by injecting water or gas into the reservoir to force additional oil 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. The rate at which the waves are transmitted varies with the medium through which they pass.
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 licence
A licence issued following the declaration of a significant discovery, which is indicated by the first exploration well that demonstrates by flow testing the existence of sufficient hydrocarbons in a particular geological feature to suggest potential for sustained production. A Significant Discovery Licence confers the same rights as that of an Exploration Licence.
Sour gas
Natural gas contaminated with chemical impurities, notably hydrogen sulphide or other sulphur compounds. Such compounds must be removed before the gas can be used for commercial or domestic purposes.
Specific Gravity
The ratio between the weight of equal volumes of water and another liquid measured at standard temperature, the weight of water is assigned a value of one (1). However, the specific gravity of oil is normally expressed in degrees of API gravity as follows:
Degrees API = | 141.5 Specific gravity @ F60 degrees | −131.5 |
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.
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Steam Assisted Gravity Drainage
A 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 to a horizontal production well beneath the steam injection well.
Step-out Well
A well drilled adjacent to a proven well but located in an unproven area; a well drilled in an effort to ascertain the extent and boundaries of a producing formation.
Stratigraphic test well
A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) “exploratory-type,” if not drilled in a proved area, or (ii) “development-type,” if drilled in a proved area.
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.
Tertiary recovery
The recovery of oil and gas by using exotic or complex recovery schemes involving steam, chemicals, gases or heat. Usually, but not necessarily, this is done after the secondary recovery phase has passed.
Three-D Seismic (survey)
Three dimensional seismic imaging which uses a grid of numerous cables rather than a few lines stretched in one line.
Turnaround
Perform maintenance at a plant or facility which requires the plant or facility to be shut completely or partially down for the duration.
Undeveloped area
An area in which it has not been established by drilling operations whether oiland/or gas may be found in commercial quantities.
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.
Well Abandonment Costs
Costs of abandoning a well (net of any salvage value) and of disconnecting the well from the surface gathering system.
Wellhead
The structure, sometimes called the “Christmas tree,” that is positioned on the surface over a well that is used to control the flow of oil or gas as it emerges from the sub surface casinghead.
Working interest
An interest in the net revenues of an oil and gas property which is proportionate to the share of exploration and development costs borne until such costs have been recovered, and which entitles the holder to participate in a share of net revenue thereafter.
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Annual Information Form are forward-looking statements or information, collectively “forward-looking statements,” within the meaning of Section 21E of the United States Securities Exchange Act of 1934, as amended, Section 27A of the United States Securities Act of 1933, as amended and of applicable Canadian Securities legislation. The Company is hereby providing cautionary statements identifying important factors that could cause the Company’s actual results to differ materially from those projected in forward-looking statements made in this Annual Information Form. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “intend,” “plan,” “projection,” “could;” “vision;” “goals;” “objective” and “outlook”) are not historical facts and may be forward-looking statements and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular reserve estimates; our plans to increase heavy oil production through the use of various enhanced recovery techniques; our exploration plans throughout the Western Canada Sedimentary Basin; our exploitation plans throughout the Western Canada Sedimentary Basin through optimizations, recompletions, workovers, enhanced recovery techniques, infill and step out drilling, additional facilities and tie-in of discovery wells; our production plans at the Tucker oil sands project; the execution of the Sunrise integration agreement with BP Corporation North America Inc.; the front-end engineering design, drilling and field work plans and timing of the Sunrise oil sands project; our drilling and development planning for the Caribou and Saleski oil sands projects; our drilling plans for the Central Mackenzie Valley; our White Rose tie-back projects including delineation and development drilling; our anticipation of regulatory approvals for our Jeanne d’Arc Basin projects; plans to capture the value of the natural gas discoveries in the Jeanne d’Arc Basin; our expectations in respect of the Terra Nova re-determination; our drilling plans at Terra Nova; our East Coast exploration plans including the results from our planned acquisition of seismic data; the results of our seismic and exploration drilling in the South China Sea and the East China Sea; the results of our seismic program and delineation drilling at the Liwan natural gas discovery in the South China Sea; the timing of delivery of the West Hercules semi-submersible drilling rig; the results of our seismic program on the East Bawean II PSC; our development plans for the BD natural gas and NGL in the Madura Strait, Indonesia; the results of our aerogravity and magnetic survey offshore Greenland; our plans for further pipe line expansion in the Cold Lake and Lloydminster areas; our plans to strategically locate new retail outlets and form strategic alliances in our downstream businesses and our plans to capture value through various business opportunities in the downstream business are forward-looking statements.
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements of the Company made by or on behalf of the Company, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include, but are not limited to:
• | fluctuations in commodity prices | |
• | the accuracy of our oil and gas reserve estimates and estimated production levels as they are affected by our success at exploration and development drilling and related activities and estimated decline rates | |
• | the uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures | |
• | changes in general economic, market and business conditions | |
• | fluctuations in supply and demand for our products | |
• | fluctuations in the cost of borrowing | |
• | our use of derivative financial instruments to hedge exposure to changes in commodity prices and fluctuations in interest rates and foreign currency exchange rates | |
• | political and economic developments, expropriations, royalty and tax increases, retroactive tax claims and changes to import and export regulations and other foreign laws and policies in the countries in which we operate | |
• | our ability to receive timely regulatory approvals | |
• | the integrity and reliability of our capital assets | |
• | the cumulative impact of other resource development projects |
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• | the maintenance of satisfactory relationships with unions, employee associations and joint venturers | |
• | competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternate sources of energy | |
• | actions by governmental authorities, including changes in environmental and other regulations that may impose restriction in areas where we operate | |
• | the ability and willingness of parties with whom we have material relationships to fulfill their obligations | |
• | the occurrence of unexpected events such as fires, blowouts,freeze-ups, equipment failures and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us and that may or may not be financially recoverable |
These and other factors are discussed throughout this Annual Information Form and in our “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” available on SEDAR atwww.sedar.com.
Further, any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.
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Schedule A
Husky Energy Inc.
AUDIT COMMITTEE CHARTER
The Audit Committee (the “Committee”) of the Board of Directors (the “Board”) of Husky Energy Inc. (the “Company”) will have the oversight responsibility, authority and specific duties as described below.
Composition
The Committee will be comprised of three or more directors as determined by the Board, each of whom shall satisfy the independence and financial literacy requirements of applicable securities regulatory requirements. In addition, one of the members of the Committee will be an audit committee financial expert as defined in applicable securities regulatory requirements. The members of the Committee will be elected annually at the organizational meeting of the full Board on the recommendation of the Corporate Governance Committee to the Co-Chairmen and will be listed in the annual report to shareholders. One of the members of the Committee will be elected Committee Chair by the Board.
Responsibility
The Committee is a part of the Board. Its primary function is to assist the Board in fulfilling its oversight responsibilities with respect to:
(i) | the quarterly and annual financial statements and quarterly and annual MD&A be provided to shareholders and the appropriate regulatory agencies; | |
(ii) | earnings press releases before the Company publicly discloses this information; | |
(iii) | the system of internal controls that management has established; | |
(iv) | the internal and external audit process; | |
(v) | the appointment of qualified reserves evaluators or auditors; and | |
(vi) | the filing of statements and reports with respect to the Company’s oil and gas reserves. |
In addition, the Committee provides an avenue for communication between the Board and each of internal audit, the external auditors, financial management, external qualified reserves evaluators or auditors and internal qualified reserves evaluators. The Committee should have a clear understanding with the external auditors and the external reserve evaluators or auditors that an open and transparent relationship must be maintained with the Committee.
The Committee will make regular reports to the Board concerning its activities.
While the Audit Committee has the responsibilities and powers set forth in this Charter, the role of the Audit committee is oversight. The members of the Committee are not full time employees of the Company and may or may not be accountants or auditors by profession or experts in the fields of accounting or auditing and, in any event, do not serve in such capacity. Consequently, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company’s financial statements are complete and accurate and are in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors and, as to reserves, the external reserve evaluators or auditors. Management and the external auditors shall also have the responsibility to conduct investigations and to assure compliance with laws and regulations and the Company’s business conduct guidelines.
Authority
Subject to the prior approval of the Board, the Committee is granted the authority to investigate any matter or activity involving financial accounting and financial reporting, the internal controls of the Company and the reporting of the Company’s reserves and oil and gas activities.
The Committee has the authority to engage independent counsel and other advisors as it determines necessary to carry out its duties and to set and pay the compensation for any advisors employed by the Committee.
In recognition of the fact that the independent auditors are ultimately accountable to the Committee, the Committee shall have the authority and responsibility to nominate for shareholder approval, evaluate and, where appropriate, replace the independent auditors and shall approve all audit engagement fees and terms and all non-audit engagements with the
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independent auditors. The Committee shall consult with management and the internal audit group but shall not delegate these responsibilities.
Meetings
The Committee is to meet at least four times annually and as many additional times as the Committee deems necessary. Committee members will strive to be present at all meetings either in person or by telephone. As necessary or desirable, but in any case at least quarterly, the Committee shall meet with members of management and representatives of the external auditors and internal audit in separate executive sessions to discuss any matters that the Committee or any of these groups believes should be discussed privately. Likewise, as necessary or desirable, but in any case at least annually, the Committee shall meet the management and representatives of the external reserve evaluators or auditors and internal reserves evaluators in separate executive sessions to discuss matters that the Committee or any of these groups believes should be discussed privately.
Specific Duties
In carrying out its oversight responsibilities, the Committee will:
1. | Review and reassess the adequacy of this Charter annually and recommend any proposed changes to the Board for approval. |
2. (a) | Review with the Company’s management, internal audit and external auditors and recommend to the Board for approval the Company’s annual financial statements and annual MD&A which is to be provided to shareholders and the appropriate regulatory agencies, including any financial statement contained in a prospectus, information circular, registration statement or other similar document. |
(b) | Review with the Company’s management, internal audit and external auditors and approve the Company’s quarterly financial statements and quarterly MD&A which is to be provided to shareholders and the appropriate regulatory agencies. |
3. | Review with the Company’s management and approve earnings press releases before the Company publicly discloses this information. | |
4. | Recommend to the Board the external auditors to be nominated for the purpose of preparing or issuing an audit report or performing other audit, review or attest services and the compensation to be paid to the external auditors. The external auditors shall report directly to the Committee. | |
5. | Be directly responsible for the oversight of the work of the external auditors, including the resolution of disagreements between management of the Company and the external auditors regarding financial reporting. | |
6. | Review with the Company’s management, internal audit and external auditors the Company’s accounting and financial reporting controls. Obtain annually in writing from the external auditors their observations, if any, on significant weaknesses in internal controls as noted during the course of their work. | |
7. | Review with the Company’s management, internal audit and external auditor’s significant accounting and reporting principles, practices and procedures applied by the Company in preparing its financial statements. Discuss with the external auditors their judgments about the quality, not just the acceptability, of the Company’s accounting principles used in financial reporting. | |
8. | Review the scope of internal audit’s work plan for the year and receive a summary report of major findings by internal auditors and how management is addressing the conditions reported. | |
9. | Review the scope and general extent of the external auditors’ annual audit. The Committee’s review should include an explanation from the external auditors of the factors considered in determining the audit scope, including the major risk factors. The external auditors should confirm to the Committee whether or not any limitations have been placed on the scope or nature of their audit procedures. | |
10. | Inquire as to the independence of the external auditors and obtain from the external auditors, at least annually, a formal written statement delineating all relationships between the external auditors and the Company as contemplated by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees. | |
11. | Have a predetermined arrangement with the external auditors that they will advise the Committee, through its Chair and management of the Company, of any matters identified through procedures followed for the review |
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of interim quarterly financial statements of the Company, and that such notification is to be made prior to the related press release. Also receive a written confirmation provided by the external auditors at the end of each of the first three quarters of the year that they have nothing to report to the Committee, if that is the case, or the written enumeration of required reporting issues. |
12. | At the completion of the annual audit, review with management, internal audit and the external auditors the following: |
• | The annual financial statements and related footnotes and financial information to be included in the Company’s annual report to shareholders. | |
• | Results of the audit of the financial statements and the related report thereon and, if applicable, a report on changes during the year in accounting principles and their application. | |
• | Significant changes to the audit plan, if any, and any serious disputes or difficulties with management encountered during the audit. Inquire about the cooperation received by the external auditors during their audit, including access to all requested records, data and information. | |
• | Inquire of the external auditors whether there have been any material disagreements with management, which, if not satisfactorily resolved, would have caused them to issue a non-standard report on the Company’s financial statements. |
13. | Discuss with the external auditors, without management being present, (a) the quality of the Company’s financial and accounting personnel, and (b) the completeness and accuracy of the Company’s financial statements. Also, elicit the comments of management regarding the responsiveness of the external auditors to the Company’s needs. | |
14. | Meet with management, to discuss any relevant significant recommendations that the external auditors may have, particularly those characterized as ’material’ or ’serious’. Typically, such recommendations will be presented by the external auditors in the form of a Letter of Comments and Recommendations to the Committee. The Committee should review responses of management to the Letter of Comments and Recommendations from the external auditors and receivefollow-up reports on action taken concerning the aforementioned recommendations. | |
15. | Have the sole authority to review in advance, and grant any appropriate pre-approvals, of all non-audit services to be provided by the independent auditors and, in connection therewith, to approve all fees and other terms of engagement. The Committee shall also review and approve disclosures required to be included in periodic reports filed with Canadian securities regulators and the Securities and Exchange Commission with respect to non-audit services performed by external auditors. | |
16. | Be satisfied that adequate procedures are in place for the review of the Company’s disclosure of financial information extracted or derived from the Company’s financial statements, and periodically assess the adequacy of those procedures. | |
17. | Establish procedures for (a) the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls or auditing matter, and (b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters. | |
18. | Review and approve the Company’s hiring policies regarding partners, employees and former partners and employees of the present and former external auditors. | |
19. | Review the appointment and replacement of the senior internal audit executive. | |
20. | Review with management, internal audit and the external auditors the methods used to establish and monitor the Company’s policies with respect to unethical or illegal activities by Company employees that may have a material impact on the financial statements. | |
21. | Generally as part of the review of the annual financial statements, receive a report(s), at least annually, from the Company’s general counsel concerning legal, regulatory and compliance matters that may have a material impact on the financial statements. | |
22. | Review, with reasonable frequency, the Company’s procedures relating to the disclosure of information with respect to the Company’s oil and gas reserves, including the Company’s procedures for complying with the disclosure requirements and restrictions of applicable regulations. |
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23. | Review with management the appointment of external qualified reserves evaluators or auditors, and in the case of any proposed change in such appointment, determine the reasons for the change and whether there have been disputes between the appointed external qualified reserves evaluators or auditors, and management. | |
24. | Review, with reasonable frequency, the Company’s procedures for providing information to the external qualified reserves evaluators or auditors who report on reserves and data for the purposes of compliance with applicable securities laws. | |
25. | Before the approval and the release of the Company’s reserves data and the report of the qualified reserve evaluators or auditors thereon, meet with management, the external qualified reserves evaluators or auditors and the internal qualified reserves evaluators to determine whether any restrictions affect their ability to report on reserves data without reservation and to review the reserves data and the report of the qualified reserves evaluators. | |
26. | Recommend to the Board for approval the content and filing of required statements and reports relating to the Company’s disclosure of reserve data as prescribed by applicable regulations. | |
27. | Review and approve (a) any change or waiver in the Company’s Code of Business Conduct for the chief executive officer and senior financial officers and (b) any public disclosure made regarding such change or waiver. |
Calgary, Alberta, Canada
February 15, 2006
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Schedule B
Husky Energy Inc.
REPORT ON RESERVES DATA BY QUALIFIED RESERVES EVALUATOR
To the Board of Directors of
HUSKY ENERGY INC. (Husky):
1. | Our staff has evaluated Husky’s oil and gas reserves data as at December 31, 2007. The reserves data consist of the following: |
(a) | proved oil and gas reserve quantities estimated as at December 31, 2007 using constant prices and costs; and | |
(b) | the related standardized measure of discounted future net cash flows. |
2. | The oil and gas reserves data are the responsibility of Husky’s management. As the Corporate Representatives our responsibility is to certify that the reserves data has been properly calculated in accordance with generally accepted procedures for the estimation of reserves data. |
3. | We carried out our evaluation in accordance with generally accepted procedures for the estimation of oil and gas reserves data and standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGEH”) with the necessary modifications to reflect definitions and standards under the applicable U.S. Financial Accounting Standards Board standards (the “FASB Standards” and the legal requirements of the U.S. Securities and Exchange Commission (“SEC Requirements”)). Our internal reserves evaluators are not independent of Husky, within the meaning of the term “independent” under those standards. |
4. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the oil and gas reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGEH as modified or replaced by the FASB Standards and SEC Requirements. |
5. | The following sets forth the estimated standardized measure of discounted future net cash flows (before deducting income taxes) attributed to proved oil and gas reserve quantities, estimated using constant prices and costs and calculated using a discount rate of 10%, included in the reserves data of Husky evaluated for the year ended December 31, 2007: |
Discounted Future Net Cash Flows | ||||
Location of Reserves | before income taxes, 10% discount rate | |||
($ millions) | ||||
Canada | 20,317 | |||
China | 651 | |||
Libya | 14 | |||
20,982 | ||||
We have filed Husky’s oil and gas reserves disclosures in accordance with Financial Accounting Standards Board Statement No. 69 “Disclosures about Oil and Gas Producing Activities” concurrently with this form.
6. | In our opinion, the oil and gas reserves data evaluated by us have, in all material respects, been determined in accordance with principles and definitions presented in the COGEH as modified or replaced by the FASB Standards and SEC Requirements. |
7. | We have no responsibility to update our evaluation for events and circumstances occurring after the date of this report. |
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8. | Oil and gas reserves are estimates only, and not exact quantities. In addition, the oil and gas reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery. |
Calgary, Alberta
January 22, 2008
/s/ Frederick Au-Yeung
Frederick Au-Yeung, P. Eng
Manager of Reservoir Engineering
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Schedule C
Husky Energy Inc.
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Management of Husky Energy Inc. (“Husky”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes oil and gas reserves data, which consist of the following:
(1) | proved oil and gas reserve quantities estimated as at December 31, 2007 using constant prices and costs; and | |
(2) | the related standardized measure of discounted future net cash flows. |
Husky’s oil and gas reserves evaluation process involves applying generally accepted procedures for the estimation of oil and gas reserves data for the purposes of complying with the legal requirements of the U.S. Securities and Exchange Commission (“SEC”) and the applicable provisions of the U.S. Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69 (collectively, the “Oil and Gas Reserves Data Process”). Husky’s Internal Qualified Reserves Evaluator is the Manager of Reservoir Engineering, who is an employee of Husky and has evaluated Husky’s oil and gas reserves data and certified that the Reserves Data Process has been followed. The Report on Reserves Data of the Manager of Reservoir Engineering accompanies this report and will be filed with securities regulatory authorities concurrently with this report.
The Audit Committee of the Board of Directors has:
(a) | reviewed the Company’s procedures for providing information to the internal and external qualified oil and gas reserves evaluators; | |
(b) | met with the internal and, if applicable, external qualified oil and gas reserves evaluator(s) to determine whether any restrictions placed by management affect the ability of the internal qualified reserves evaluator to report without reservation; and | |
(c) | reviewed the reserves data with management and the internal qualified oil and gas reserves evaluator. |
The Audit Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has approved, on the recommendation of the Audit Committee:
(a) | the content and filing with securities regulatory authorities of Form51-101F1 containing reserves data and other oil and gas information; | |
(b) | the filing ofForm 51-101F2, which is the Report on Reserves Data of the Manager of Reservoir Engineering; and | |
(c) | the content and filing of this report. |
Husky sought and was granted by the Canadian Securities Administrators an exemption from the requirement under National Instrument51-101 “Standards of Disclosure for Oil and Gas Disclosure” to involve independent qualified oil and gas reserves evaluators or auditors. Notwithstanding this exemption, we involve independent qualified reserve auditors as part of Husky’s corporate governance practices. Their involvement helps assure that our internal oil and gas reserves estimates are materially correct.
In Husky’s view, the reliability of Husky’s internally generated oil and gas reserves data is not materially different than would be afforded by Husky involving independent qualified reserves evaluators or independent qualified reserves auditors to evaluate or audit and review the reserves data. Husky is therefore relying on an exemption, which it sought and was granted by securities regulatory authorities, from the requirement under securities legislation to involve independent qualified reserves evaluators or independent qualified reserves auditors.
The primary factors supporting the involvement of independent qualified reserves evaluators or independent qualified reserves auditors apply when (i) their knowledge of, and experience with, a reporting issuer’s reserves data are superior to that of the internal evaluators and (ii) the work of the independent qualified reserves evaluator or independent qualified reserves auditors is significantly less likely to be adversely influenced by self-interest or management of the reporting issuer than the work of internal reserves evaluation staff. In Husky’s view, neither of these factors applies in Husky’s circumstances.
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Husky’s view is based in large part on the following. Our reserves data were developed in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook. Husky’s procedures, records and controls relating to the accumulation of source data and preparation of reserves data by Husky’s internal reserves evaluation staff have been established, refined and documented over many years. Our internal reserves evaluation staff includes 101 individuals, including support staff, of whom 50 individuals are qualified reserves evaluators as defined in the Canadian Oil and Gas Evaluation Handbook, with an average of 14 years of relevant experience in evaluating reserves. Husky’s internal reserves evaluation management personnel includes 19 individuals with an average of 15 years of relevant experience in evaluating oil and gas and managing the evaluation process.
Reserves data are estimates only, and are not exact quantities. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.
/s/ John C. S. Lau John C. S. Lau President & Chief Executive Officer | March 10, 2008 | |
/s/ James D. Girgulis James D. Girgulis Vice President, Legal & Corporate Secretary | March 10, 2008 | |
/s/ R. Donald Fullerton R. Donald Fullerton Director | March 10, 2008 | |
/s/ William Shurniak William Shurniak Director | March 10, 2008 |
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Schedule D
Husky Energy Inc.
INDEPENDENT ENGINEER’S AUDIT OPINION
Husky Energy Inc.
707 — 8th Avenue S.W.
Calgary, Alberta
T2P 3G7
Gentlemen:
Pursuant to Husky’s request we have conducted an audit of the reserves estimates and the respective present worth value of these reserves of Husky Energy Inc., as at December 31, 2007. The Company’s detailed reserves information was provided to us for this audit. Our responsibility is to express an independent opinion on the reserves and respective present worth value estimates, in aggregate, based on our audit tests and procedures.
We conducted our audit in accordance with Canadian generally accepted standards as described in the Canadian Oil and Gas Evaluation Handbook (COGEH) and auditing standards generally accepted in the United States of America. Those standards require that we review and assess the policies, procedures, documentation and guidelines of the Company with respect to the estimation, review and approval of Husky’s reserves information. An audit includes examining, on a test basis, to confirm that there is adherence on the part of Husky’s internal reserve evaluators and other employees to the reserves management and administration policies and procedures established by the Company. An audit also includes conducting reserves evaluation on sufficient number of Company properties as considered necessary to express an opinion.
Based on the results of our audit, it is our opinion that Husky’s internally generated proved and probable reserves and net present values based on forecast and constant price assumptions are, in aggregate, reasonable and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices in the United States and as set out in the Canadian Oil and Gas Evaluation Handbook.
Sincerely,
MCDANIEL & ASSOCIATES CONSULTANTS LTD.
/s/ P.A. Welch
P.A. Welch, P. Eng.
President & Managing Director
Calgary, Alberta
January 22, 2008
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Document B
Form 40-F
CONSOLIDATED FINANCIAL STATEMENTS AND
AUDITORS’ REPORT TO SHAREHOLDERS
For the Year Ended December 31, 2007
Table of Contents
Husky Energy Inc.
Consolidated Financial Statements
For the Year Ended December 31, 2007
Table of Contents
MANAGEMENT’S REPORT
The management of Husky Energy Inc. is responsible for the financial information and operating data presented in this financial document.
The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise as they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects. Financial information presented elsewhere in this financial document has been prepared on a basis consistent with that in the consolidated financial statements.
Husky Energy Inc. maintains systems of internal accounting and administrative controls. These systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are properly accounted for and adequately safeguarded. Management evaluation concluded that our internal control over financial reporting was effective as of December 31, 2007. The system of internal controls is further supported by an internal audit function.
The Company excluded from its assessment the internal control over financial reporting at our Lima, Ohio refinery, which was acquired effective July 1, 2007. The operations of the Lima refinery are currently being integrated into our operations, including assessing and designing internal controls over financial reporting and disclosure controls and procedures for the Lima refinery operations. At December 31, 2007, total assets of the Lima, Ohio refinery accounted for 14% of the Company’s total consolidated assets and total revenues from the Lima refinery accounted for 15% of the Company’s total consolidated revenues and are included in the December 31, 2007 consolidated financial statements.
The Audit Committee of the Board of Directors, composed of independent non-management directors, meets regularly with management, as well as the external auditors, to discuss auditing (external, internal and joint venture), internal controls, accounting policy, financial reporting matters and reserves determination process. The Committee reviews the annual consolidated financial statements with both management and the independent auditors and reports its findings to the Board of Directors before such statements are approved by the Board. The Committee is also responsible for the appointment of the external auditors for the Company.
The consolidated financial statements have been audited by KPMGllp, the independent auditors, in accordance with Canadian generally accepted auditing standards on behalf of the shareholders. KPMGllp has full and free access to the Audit Committee.
/s/ John C. S. Lau
John C. S. Lau
President & Chief Executive Officer
Calgary, Alberta, Canada
February 4, 2008
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AUDITORS’ REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheets of Husky Energy Inc. (“the Company”) as at December 31, 2007, 2006 and 2005 and the consolidated statements of earnings and comprehensive income, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. With respect to the consolidated financial statements for the years ended December 31, 2007 and 2006, we also conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2007 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007 in accordance with Canadian generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 4, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG llp
KPMGllp
Chartered Accountants
Calgary, Alberta, Canada
February 4, 2008
Comments by auditors for US readers on Canada — US Reporting Differences
To the Board of Directors of Husky Energy Inc. (the “Company”)
In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Company’s financial statements, such as the change described in Note 19 (Financial Instruments and Risk Management) to the consolidated financial statements as at December 31, 2007, and for the year then ended. Our report to the shareholders dated February 4, 2008 is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.
/s/ KPMG llp
KPMGllp
Chartered Accountants
Calgary, Canada
February 4, 2008
February 4, 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Husky Energy Inc.
We have audited Husky Energy Inc. (“the Company”)’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The Management of Husky Energy Inc. excluded from its assessment the internal control over financial reporting at the Lima refinery, which was acquired effective July 1, 2007. Our audit of internal control over financial reporting of Husky Energy Inc. also excluded an evaluation of the internal control over financial reporting of the Lima refinery.
We also have conducted our audits on the consolidated financial statements in accordance with Canadian generally accepted auditing standards. With respect to the consolidated financial statements for the years ended December 31, 2007 and 2006, we also have conducted our audits on the consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated February 4, 2008, expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG llp
KPMGllp
Chartered Accountants
Calgary, Canada
February 4, 2008
February 4, 2008
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CONSOLIDATED BALANCE SHEETS
As at December 31 | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(millions of dollars) | ||||||||||||
ASSETS | ||||||||||||
Current assets | ||||||||||||
Cash and cash equivalents | $ | 208 | $ | 442 | $ | 168 | ||||||
Accounts receivable(notes 5, 19) | 1,622 | 1,284 | 856 | |||||||||
Inventories(note 6) | 1,190 | 428 | 471 | |||||||||
Prepaid expenses | 28 | 25 | 40 | |||||||||
3,048 | 2,179 | 1,535 | ||||||||||
Property, plant and equipment, net(notes 1, 7) | 17,805 | 15,550 | 13,959 | |||||||||
Goodwill(notes 1, 8) | 660 | 160 | 160 | |||||||||
Other assets(notes 12, 19) | 184 | 44 | 62 | |||||||||
$ | 21,697 | $ | 17,933 | $ | 15,716 | |||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||||||
Current liabilities | ||||||||||||
Accounts payable and accrued liabilities(note 11) | $ | 2,358 | $ | 2,574 | $ | 2,310 | ||||||
Long-term debt due within one year(notes 12, 19) | 741 | 100 | 274 | |||||||||
3,099 | 2,674 | 2,584 | ||||||||||
Long-term debt(notes 12, 19) | 2,073 | 1,511 | 1,612 | |||||||||
Other long-term liabilities(note 13) | 918 | 756 | 730 | |||||||||
Future income taxes(note 14) | 3,957 | 3,372 | 3,270 | |||||||||
Commitments and contingencies(note 15) | ||||||||||||
Shareholders’ equity | ||||||||||||
Common shares(note 16) | 3,551 | 3,533 | 3,523 | |||||||||
Retained earnings | 8,176 | 6,087 | 3,997 | |||||||||
Accumulated other comprehensive income | (77 | ) | — | — | ||||||||
11,650 | 9,620 | 7,520 | ||||||||||
$ | 21,697 | $ | 17,933 | $ | 15,716 | |||||||
On behalf of the Board:
/s/John C. S. Lau | /s/R.D. Fullerton | |
John C. S. Lau | R.D. Fullerton | |
Director | Director |
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME
Year ended December 31 | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(millions of dollars, | ||||||||||||
except per share amounts) | ||||||||||||
Sales and operating revenues, net of royalties | $ | 15,518 | $ | 12,664 | $ | 10,245 | ||||||
Costs and expenses | ||||||||||||
Cost of sales and operating expenses(note 13) | 9,296 | 7,169 | 5,917 | |||||||||
Selling and administration expenses | 219 | 162 | 138 | |||||||||
Stock-based compensation(note 16) | 88 | 138 | 171 | |||||||||
Depletion, depreciation and amortization(notes 1, 7) | 1,806 | 1,599 | 1,256 | |||||||||
Interest — net(note 12) | 130 | 92 | 32 | |||||||||
Foreign exchange(note 12) | (51 | ) | (24 | ) | (31 | ) | ||||||
Other — net(notes 15, 19) | (97 | ) | 22 | (50 | ) | |||||||
11,391 | 9,158 | 7,433 | ||||||||||
Earnings before income taxes | 4,127 | 3,506 | 2,812 | |||||||||
Income taxes(note 14) | ||||||||||||
Current | 347 | 678 | 297 | |||||||||
Future | 566 | 102 | 512 | |||||||||
913 | 780 | 809 | ||||||||||
Net earnings | 3,214 | 2,726 | 2,003 | |||||||||
Other comprehensive income | ||||||||||||
Derivatives designated as cash flow hedges, net of tax(note 19) | 14 | — | — | |||||||||
Cumulative foreign currency translation adjustment | (175 | ) | — | — | ||||||||
Hedge of net investment, net of tax(note 19) | 102 | — | — | |||||||||
(59 | ) | — | — | |||||||||
Comprehensive income | $ | 3,155 | $ | 2,726 | $ | 2,003 | ||||||
Earnings per share | ||||||||||||
Basic and diluted(note 16) | $ | 3.79 | $ | 3.21 | $ | 2.36 | ||||||
Weighted average number of common shares outstanding(millions) | ||||||||||||
Basic and diluted(note 16) | 848.8 | 848.4 | 847.9 | |||||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Year ended December 31 | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(millions of dollars) | ||||||||||||
Common shares | ||||||||||||
Beginning of year | $ | 3,533 | $ | 3,523 | $ | 3,506 | ||||||
Options and warrants exercised | 18 | 10 | 17 | |||||||||
End of year | 3,551 | 3,533 | 3,523 | |||||||||
Retained earnings | ||||||||||||
Beginning of year | 6,087 | 3,997 | 2,694 | |||||||||
Net earnings | 3,214 | 2,726 | 2,003 | |||||||||
Dividends on common shares(note 16) | ||||||||||||
Ordinary | (917 | ) | (636 | ) | (276 | ) | ||||||
Special | (212 | ) | — | (424 | ) | |||||||
Adoption of financial instruments(note 19) | 4 | — | — | |||||||||
End of year | 8,176 | 6,087 | 3,997 | |||||||||
Accumulated other comprehensive income | ||||||||||||
Beginning of year | — | — | — | |||||||||
Adoption of financial instruments(note 19) | (18 | ) | — | — | ||||||||
Other comprehensive income | ||||||||||||
Derivatives designated as cash flow hedges, net of tax(note 19) | 14 | — | — | |||||||||
Cumulative foreign currency translation adjustment | (175 | ) | — | — | ||||||||
Hedge of net investment, net of tax(note 19) | 102 | — | — | |||||||||
(59 | ) | — | — | |||||||||
End of year | (77 | ) | — | — | ||||||||
Shareholders’ equity | $ | 11,650 | $ | 9,620 | $ | 7,520 | ||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(millions of dollars) | ||||||||||||
Operating activities | ||||||||||||
Net earnings | $ | 3,214 | $ | 2,726 | $ | 2,003 | ||||||
Items not affecting cash | ||||||||||||
Accretion(note 13) | 47 | 45 | 33 | |||||||||
Depletion, depreciation and amortization | 1,806 | 1,599 | 1,256 | |||||||||
Future income taxes | 566 | 102 | 512 | |||||||||
Foreign exchange | (135 | ) | (3 | ) | (37 | ) | ||||||
Other | (72 | ) | 32 | 18 | ||||||||
Settlement of asset retirement obligations(note 13) | (51 | ) | (36 | ) | (41 | ) | ||||||
Change in non-cash working capital(note 9) | (718 | ) | 544 | (94 | ) | |||||||
Cash flow — operating activities | 4,657 | 5,009 | 3,650 | |||||||||
Financing activities | ||||||||||||
Bank operating loans financing — net | — | — | (101 | ) | ||||||||
Long-term debt issue | 7,222 | 1,226 | 3,235 | |||||||||
Long-term debt repayment | (5,722 | ) | (1,493 | ) | (3,401 | ) | ||||||
Settlement of cross currency swap | — | (47 | ) | — | ||||||||
Debt issue costs | (8 | ) | — | — | ||||||||
Proceeds from exercise of stock options | 5 | 3 | 6 | |||||||||
Proceeds from monetization of financial instruments | — | — | 39 | |||||||||
Dividends on common shares | (1,129 | ) | (636 | ) | (700 | ) | ||||||
Other | — | (1 | ) | (1 | ) | |||||||
Change in non-cash working capital(note 9) | 65 | (678 | ) | 255 | ||||||||
Cash flow — financing activities | 433 | (1,626 | ) | (668 | ) | |||||||
Available for investing | 5,090 | 3,383 | 2,982 | |||||||||
Investing activities | ||||||||||||
Capital expenditures | (2,931 | ) | (3,171 | ) | (3,068 | ) | ||||||
Corporate acquisition(note 8) | (2,589 | ) | — | — | ||||||||
Asset sales | 333 | 34 | 74 | |||||||||
Other | (44 | ) | (12 | ) | (31 | ) | ||||||
Change in non-cash working capital(note 9) | (93 | ) | 40 | 211 | ||||||||
Cash flow — investing activities | (5,324 | ) | (3,109 | ) | (2,814 | ) | ||||||
Increase (decrease) in cash and cash equivalents | (234 | ) | 274 | 168 | ||||||||
Cash and cash equivalents at beginning of year | 442 | 168 | — | |||||||||
Cash and cash equivalents at end of year | $ | 208 | $ | 442 | $ | 168 | ||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Except where indicated and per share amounts, all dollar amounts are in millions.
Note 1
Segmented Financial Information
Upstream | Midstream | |||||||||||||||||||||||||||||||||||
Infrastructure | ||||||||||||||||||||||||||||||||||||
Upgrading | and Marketing | |||||||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||||||||||||
Year ended December 31 | ||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 6,222 | $ | 5,772 | $ | 4,367 | $ | 1,524 | $ | 1,679 | $ | 1,488 | $ | 10,217 | $ | 9,559 | $ | 7,383 | ||||||||||||||||||
Costs and expenses | ||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 1,308 | 1,321 | 1,050 | 1,127 | 1,273 | 1,018 | 9,838 | 9,258 | 7,084 | |||||||||||||||||||||||||||
Depletion, depreciation and amortization | 1,615 | 1,476 | 1,144 | 25 | 24 | 21 | 28 | 24 | 21 | |||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
2,923 | 2,797 | 2,194 | 1,152 | 1,297 | 1,039 | 9,866 | 9,282 | 7,105 | ||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 3,299 | 2,975 | 2,173 | 372 | 382 | 449 | 351 | 277 | 278 | |||||||||||||||||||||||||||
Current income taxes | 122 | 519 | 215 | 10 | 53 | 16 | 68 | 79 | (14 | ) | ||||||||||||||||||||||||||
Future income taxes | 581 | 161 | 434 | 80 | 44 | 120 | 30 | 1 | 110 | |||||||||||||||||||||||||||
Net earnings (loss) | $ | 2,596 | $ | 2,295 | $ | 1,524 | $ | 282 | $ | 285 | $ | 313 | $ | 253 | $ | 197 | $ | 182 | ||||||||||||||||||
Property, plant and equipment — As at December 31 | ||||||||||||||||||||||||||||||||||||
Cost | $ | 23,611 | $ | 21,770 | $ | 19,167 | $ | 1,607 | $ | 1,390 | $ | 1,205 | $ | 842 | $ | 750 | $ | 683 | ||||||||||||||||||
Accumulated depletion, depreciation and amortization | 9,956 | 8,545 | 7,083 | 480 | 455 | 430 | 298 | 270 | 247 | |||||||||||||||||||||||||||
Net | $ | 13,655 | $ | 13,225 | $ | 12,084 | $ | 1,127 | $ | 935 | $ | 775 | $ | 544 | $ | 480 | $ | 436 | ||||||||||||||||||
Capital expenditures — Year ended December 31(1) | $ | 2,388 | $ | 2,627 | $ | 2,730 | $ | 217 | $ | 184 | $ | 120 | $ | 92 | $ | 68 | $ | 37 | ||||||||||||||||||
Goodwill additions — Year ended December 31 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||
Total assets — As at December 31 | $ | 14,395 | $ | 13,920 | $ | 12,887 | $ | 1,405 | $ | 992 | $ | 844 | $ | 1,134 | $ | 1,329 | $ | 866 | ||||||||||||||||||
(1) | Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions. |
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Corporate and | ||||||||||||||||||||||||||||||||||||||||||||||||
Downstream | Eliminations(1) | Total | ||||||||||||||||||||||||||||||||||||||||||||||
Canadian | U.S. | |||||||||||||||||||||||||||||||||||||||||||||||
Refined Products | Refining and Marketing | |||||||||||||||||||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||||||||||||||
Year ended December 31 | ||||||||||||||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 2,916 | $ | 2,575 | $ | 2,345 | $ | 2,383 | $ | — | $ | — | $ | (7,744 | ) | $ | (6,921 | ) | $ | (5,338 | ) | $ | 15,518 | $ | 12,664 | $ | 10,245 | |||||||||||||||||||||
Costs and expenses | ||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 2,608 | 2,381 | 2,169 | 2,167 | — | — | (7,542 | ) | (6,742 | ) | (5,145 | ) | 9,506 | 7,491 | 6,176 | |||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 66 | 48 | 47 | 47 | — | — | 25 | 27 | 23 | 1,806 | 1,599 | 1,256 | ||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | 1 | — | — | 129 | 92 | 32 | 130 | 92 | 32 | ||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | (51 | ) | (24 | ) | (31 | ) | (51 | ) | (24 | ) | (31 | ) | ||||||||||||||||||||||||||||||
2,674 | 2,429 | 2,216 | 2,215 | — | — | (7,439 | ) | (6,647 | ) | (5,121 | ) | 11,391 | 9,158 | 7,433 | ||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 242 | 146 | 129 | 168 | — | — | (305 | ) | (274 | ) | (217 | ) | 4,127 | 3,506 | 2,812 | |||||||||||||||||||||||||||||||||
Current income taxes | 17 | 19 | (3 | ) | 28 | — | — | 102 | 8 | 83 | 347 | 678 | 297 | |||||||||||||||||||||||||||||||||||
Future income taxes | 33 | 21 | 50 | 35 | — | — | (193 | ) | (125 | ) | (202 | ) | 566 | 102 | 512 | |||||||||||||||||||||||||||||||||
Net earnings (loss) | $ | 192 | $ | 106 | $ | 82 | $ | 105 | $ | — | $ | — | $ | (214 | ) | $ | (157 | ) | $ | (98 | ) | $ | 3,214 | $ | 2,726 | $ | 2,003 | |||||||||||||||||||||
Property, plant and equipment — As at December 31 | �� | |||||||||||||||||||||||||||||||||||||||||||||||
Cost | $ | 1,550 | $ | 1,344 | $ | 1,063 | $ | 1,459 | $ | — | $ | — | $ | 338 | $ | 298 | $ | 257 | $ | 29,407 | $ | 25,552 | $ | 22,375 | ||||||||||||||||||||||||
Accumulated depletion, depreciation and amortization | 590 | 525 | 476 | 46 | — | — | 232 | 207 | 180 | 11,602 | 10,002 | 8,416 | ||||||||||||||||||||||||||||||||||||
Net | $ | 960 | $ | 819 | $ | 587 | $ | 1,413 | $ | — | $ | — | $ | 106 | $ | 91 | $ | 77 | $ | 17,805 | $ | 15,550 | $ | 13,959 | ||||||||||||||||||||||||
Capital expenditures — Year ended December 31(2) | $ | 212 | $ | 285 | $ | 191 | $ | 21 | $ | — | $ | — | $ | 44 | $ | 37 | $ | 21 | $ | 2,974 | $ | 3,201 | $ | 3,099 | ||||||||||||||||||||||||
Goodwill additions — Year ended December 31 | $ | — | $ | — | $ | — | $ | 500 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 500 | $ | — | $ | — | ||||||||||||||||||||||||
Total assets — As at December 31 | $ | 1,335 | $ | 1,114 | $ | 834 | $ | 3,058 | $ | — | $ | — | $ | 370 | $ | 578 | $ | 285 | $ | 21,697 | $ | 17,933 | $ | 15,716 | ||||||||||||||||||||||||
(1) | Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventories. |
(2) | Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions. |
Geographical Financial Information
Other | ||||||||||||||||||||||||||||||||||||||||||||||||
Canada | United States | International | Total | |||||||||||||||||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||||||||||||||
Year ended December 31 | ||||||||||||||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 11,736 | $ | 11,050 | $ | 8,500 | $ | 3,494 | $ | 1,340 | $ | 1,407 | $ | 288 | $ | 274 | $ | 338 | $ | 15,518 | $ | 12,664 | $ | 10,245 | ||||||||||||||||||||||||
Capital expenditures(1) | 2,877 | 3,104 | 3,021 | 21 | — | — | 76 | 97 | 78 | 2,974 | 3,201 | 3,099 | ||||||||||||||||||||||||||||||||||||
As at December 31 | ||||||||||||||||||||||||||||||||||||||||||||||||
Property, plant and equipment, net | $ | 16,017 | $ | 15,200 | $ | 13,655 | $ | 1,417 | $ | 3 | $ | 3 | $ | 371 | $ | 347 | $ | 301 | $ | 17,805 | $ | 15,550 | $ | 13,959 | ||||||||||||||||||||||||
Goodwill(2) | 160 | 160 | 160 | 500 | — | — | — | — | — | 660 | 160 | 160 | ||||||||||||||||||||||||||||||||||||
Total assets | 17,983 | 17,443 | 15,157 | 3,240 | 115 | 231 | 474 | 375 | 328 | 21,697 | 17,933 | 15,716 | ||||||||||||||||||||||||||||||||||||
(1) | Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions. |
(2) | Changes in goodwill for the U.S. arise from translation of goodwill in our self-sustaining U.S. operations. Refer to note 8, Corporate Acquisition. |
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Note 2
Nature of Operations and Organization
Husky Energy Inc. (“Husky” or “the Company”) is a publicly traded, integrated energy and energy-related company headquartered in Calgary, Alberta, Canada.
Management has segmented the Company’s business based on differences in products and services and management responsibility. The Company’s business is conducted predominantly through three major business segments — upstream, midstream and downstream.
Upstream includes exploration for, development and production of crude oil, natural gas and natural gas liquids. The Company’s upstream operations are located primarily in Western Canada, offshore Eastern Canada, offshore Greenland, offshore China and offshore Indonesia.
Midstream includes upgrading of heavy crude oil feedstock into synthetic crude oil (upgrading); marketing of the Company’s and other producers’ crude oil, natural gas, natural gas liquids, sulphur and petroleum coke; and pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent and natural gas and cogeneration of electrical and thermal energy (infrastructure and marketing).
Downstream includes refining in Canada of crude oil and marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products (Canadian refined products) and refining in the U.S. of primarily light sweet crude oil to produce and market gasoline, jet fuel and diesel fuels that meet U.S. clean fuels standards (U.S. refining and marketing).
Note 3
Significant Accounting Policies
a) Principles of Consolidation and the Preparation of Financial Statements
These financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) which, in the case of the Company, differ in certain respects from those in the United States. These differences are described in the section, Reconciliation to Accounting Principles Generally Accepted in the United States, included in theForm 40-F.
The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from these estimates.
Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively by including these changes in the opening balance of each affected component of equity for the earliest period presented. Changes in accounting estimates are applied prospectively.
The consolidated financial statements include the accounts of Husky Energy Inc. and its subsidiaries after the elimination of intercompany balances and transactions. The Company consolidates all investments in which it has either direct or indirect voting ownership in excess of 50%. In addition, the Company consolidates variable interest entities when it is deemed to be the primary beneficiary.
Substantially all of the Company’s upstream activities are conducted jointly with third parties and accordingly the accounts reflect the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flow from these activities.
b) Cash and Cash Equivalents
Cash and cash equivalents consist of cash on hand less outstanding cheques and deposits with a maturity of less than three months at the time of purchase. When outstanding cheques are in excess of cash on hand, the excess is reported in bank operating loans.
c) Inventory Valuation
Crude oil, natural gas, refined petroleum products and purchased sulphur inventories are valued at the lower of cost or net realizable value. Cost is determined using average cost or on afirst-in, first-out basis, as appropriate. Materials and supplies are valued at the lower of average cost or net realizable value. Cost consists of raw material, labour, direct overhead and transportation. Intersegment profits are eliminated.
d) Precious Metals
The Company uses precious metals in conjunction with catalyst as part of the downstream U.S. refining process. These precious metals remain intact; however, there is a loss during the reclamation process. The estimated loss is amortized to operating expenses over the period that the precious metal is in use, which is approximately two to five years. After the reclamation process, the actual loss is compared to the estimated loss and any difference is recognized in earnings.
e) Property, Plant and Equipment
i) Oil and Gas
The Company employs the full cost method of accounting for oil and gas interests whereby all costs of acquisition, exploration for and development of oil and gas reserves are capitalized and accumulated within cost centres on acountry-by-country basis. Such costs include land acquisition, geological and geophysical activity, drilling of productive and non-productive wells, carrying costs directly related to unproved properties and administrative costs directly related to exploration and development activities.
The provision for depletion of oil and gas properties and depreciation of associated production facilities is calculated using the unit of production method, based on gross proved oil and gas reserves as estimated by the Company’s engineers, for each cost centre. Depreciation of gas plants and certain other oil and gas facilities is provided using the straight-line method based on their estimated useful lives. Costs subject to depletion and depreciation include both the estimated costs required to develop proved undeveloped reserves and the associated
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addition to the asset retirement obligations. In the normal course of operations, retirements of oil and gas interests are accounted for by charging the asset cost, net of any proceeds, to accumulated depletion or depreciation. Gains or losses on the disposition of oil and gas properties are not recognized unless the gain or loss changes the depletion rate by 20% or more.
Costs of acquiring and evaluating significant unproved oil and gas interests are excluded from costs subject to depletion and depreciation until it is determined that proved oil and gas reserves are attributable to such interests or until impairment occurs. Costs of major development projects are excluded from costs subject to depletion and depreciation until proved developed reserves have been attributed to a portion of the property or the property is determined to be impaired.
Impairment losses are recognized when the carrying amount of a cost centre exceeds the sum of:
• | the undiscounted cash flow expected to result from production from proved reserves based on forecast oil and gas prices and costs; | |
• | the costs of unproved properties, less impairment; and | |
• | the costs of major development projects, less impairment. |
The amount of impairment loss is determined to be the amount by which the carrying amount of the cost centre exceeds the sum of:
• | the fair value of proved and probable reserves; and | |
• | the cost, less impairment, of unproved properties and major development projects that do not have probable reserves attributed to them. |
ii) Other Plant and Equipment
Depreciation for substantially all other plant and equipment, except upgrading assets, is provided using the straight-line method based on estimated useful lives of assets which range from five to 35 years. Depreciation for upgrading assets is provided using the unit of production method, based on the plant’s estimated productive life. Repairs and maintenance costs, other than major turnaround costs, are charged to earnings as incurred. Certain turnaround costs are deferred to other assets when incurred and amortized over the estimated period of time to the next scheduled turnaround. At the time of disposition of plant and equipment, accounts are relieved of the asset values and accumulated depreciation and any resulting gain or loss is reflected in earnings.
iii) Asset Retirement Obligations
The recognition of the fair value of obligations associated with the retirement of tangible long-lived assets is recorded in the period that the asset is put into use, with a corresponding increase to the carrying value of the related asset. The obligations recognized are legal obligations. The liability is accreted over time for changes in the fair value of the liability through charges to accretion, which is included in cost of sales and operating expenses. The liability will also be adjusted to reflect revisions to the previous estimates of the undiscounted obligation. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion, depreciation and amortization of the underlying asset. Retirement expenditures are charged to the accumulated liability as incurred.
iv) Capitalized Interest
Interest is capitalized on significant major capital projects based on the Company’s long-term cost of borrowing. Capitalization of interest ceases when the capital project is substantially complete and ready for its intended use.
f) Impairment or Disposal of Long-lived Assets
An impairment loss is recognized when the carrying value of a long-lived asset is not recoverable and exceeds its fair value. Testing for recoverability uses the undiscounted cash flows expected from the asset’s use and disposition. To test for and measure impairment, long-lived assets are grouped at the lowest level for which identifiable cash flows are largely independent.
A long-lived asset that meets the conditions as held for sale is measured at the lower of its carrying amount or fair value less costs to sell. Such assets are not amortized while they are classified as held for sale. The results of operations of a component of an entity that has been disposed of, or is classified as held for sale, are reported in discontinued operations if: i) the operations and cash flows of the component have been or will be eliminated as a result of the disposal transaction; and, ii) the entity will not have a significant continuing involvement in the operations of the component after the disposal transaction.
g) Goodwill
Goodwill is the excess of the purchase price paid over the fair value of net assets acquired. Goodwill is subject to impairment tests on at least an annual basis or sooner if there are indicators of impairment. The Company tests impairment annually in the fourth quarter of each year. To assess impairment, the fair value of the reporting unit is compared with its carrying amount. If any potential impairment is indicated, then it is quantified by comparing the carrying value of goodwill to its fair value, determined based on the fair value of the assets and liabilities of the reporting unit. Impairment losses would be recognized in current period earnings.
h) Derivative Financial Instruments and Hedging Activities
i) Financial Instruments
All financial instruments must initially be recognized at fair value on the balance sheet. The Company has classified each financial instrument into the following categories: held for trading financial assets and financial liabilities, loans or receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. Gains and losses on available for sale financial assets are recognized in other comprehensive income (“OCI”) and are transferred to earnings when the asset is derecognized. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method.
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A held for trading financial instrument is not a loan or receivable and includes one of the following criteria:
• | is a derivative, except for those derivatives that have been designated as effective hedging instruments; | |
• | has been acquired or incurred principally for the purpose of selling or repurchasing in the near future; or | |
• | is part of a portfolio of financial instruments that are managed together and for which there is evidence of a recent actual pattern of short-term profit taking. |
For financial assets and financial liabilities that are not classified as held for trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are added to the fair value initially recognized for that financial instrument. These costs are expensed to earnings using the effective interest rate method.
ii) Derivative Instruments and Hedging Activities
Derivative instruments are utilized by the Company to manage market risk against the volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company’s policy is not to utilize derivative instruments for speculative purposes. The Company may choose to designate derivative instruments as hedges. Hedge accounting continues to be optional.
At the inception of a hedge, if the Company elects to use hedge accounting, the Company formally documents the designation of the hedge, the risk management objectives, the hedging relationships between the hedged items and hedging items and the method for testing the effectiveness of the hedge, which must be reasonably assured over the term of the hedge. This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company formally assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.
All derivative instruments are recorded on the balance sheet at fair value in either accounts receivable, other assets, accounts payable and accrued liabilities, or other long-term liabilities. Freestanding derivative instruments are classified as held for trading financial instruments. Gains and losses on these instruments are recorded in other expenses in the consolidated statement of earnings in the period they occur. Derivative instruments that have been designated and qualify for hedge accounting have been classified as either fair value or cash flow hedges. For fair value hedges, the gains or losses arising from adjusting the derivative to its fair value are recognized immediately in earnings along with the gain or loss on the hedged item. For cash flow hedges, the effective portion of the gains and losses is recorded in OCI until the hedged transaction is recognized in earnings. When the earnings impact of the underlying hedged transaction is recognized in the consolidated statement of earnings, the fair value of the associated cash flow hedge is reclassified from OCI into earnings. Any hedge ineffectiveness is immediately recognized in earnings. Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting.
The Company may enter into commodity price contracts to hedge anticipated sales of crude oil and natural gas production to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in upstream oil and gas revenues as the related sales occur.
The Company may enter into commodity price contracts to offset fixed price contracts entered into with customers and suppliers to retain market prices while meeting customer or supplier pricing requirements. Gains and losses from these contracts are recognized in midstream revenues or costs of sales.
The Company may enter into power price contracts to hedge anticipated purchases of electricity to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in upstream operating expenses as the related purchases occur.
The Company may enter into interest rate swap agreements to hedge its fixed and floating interest rate mix on long-term debt. Gains and losses from these contracts are recognized as an adjustment to the interest expense on the hedged debt instrument.
The Company may enter into foreign exchange contracts to hedge its foreign currency exposures on U.S. dollar denominated long-term debt. Gains and losses on these instruments related to foreign exchange are recorded in the foreign exchange expense in the period to which they relate, offsetting the respective foreign exchange gains and losses recognized on the underlying foreign currency long-term debt. The remaining portion of the gain or loss is recorded in accumulated other comprehensive income and is adjusted for changes in the fair value of the instrument over the life of the debt.
The Company may designate certain U.S. dollar denominated debt as a hedge of its net investment in self-sustaining foreign operations. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in OCI, net of tax and are limited to the translation gain or loss on the net investment.
The Company may enter into foreign exchange forwards and foreign exchange collars to hedge anticipated U.S. dollar denominated crude oil and natural gas sales. Gains and losses on these instruments are recognized in upstream oil and gas revenues when the sale is recorded.
For cash flow hedges that have been terminated or cease to be effective, prospective gains or losses on the derivative are recognized in earnings. Any gain or loss that has been included in accumulated other comprehensive income at the time the hedge is discontinued continues to be deferred in accumulated other comprehensive income until the original hedged transaction is recognized in earnings. However, if the likelihood of the original hedged transaction occurring is no longer probable, the entire gain or loss in accumulated other comprehensive income related to this transaction is immediately reclassified to earnings.
Fair values of the derivatives are based on quoted market prices where available. The fair values of swaps and forwards are based on forward market prices. If a forward price is not available for a commodity based forward, a forward price is estimated using an existing forward price adjusted for quality or location.
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iii) Embedded Derivatives
Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not classified as held for trading or designated at fair value. The Company selected January 1, 2003 as its transition date for accounting for any potential embedded derivatives.
The Company may enter into foreign exchange contracts to offset its foreign exchange exposure. Gains and losses on these instruments are recorded at fair value and are recognized in other expense in the consolidated statement of earnings.
iv) Comprehensive Income
Comprehensive income consists of net earnings and OCI. OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge or net investment hedge and exchange gains and losses arising from the translation of the financial statements of a self-sustaining foreign operation. Amounts included in OCI are shown net of tax. Accumulated other comprehensive income is an equity category comprised of the cumulative amounts of OCI.
i) Employee Future Benefits
In Canada, the Company provides a defined contribution pension plan and a post-retirement health and dental care plan to qualified employees. The Company also maintains a defined benefit pension plan for a small number of employees who did not choose to join the defined contribution pension plan in 1991. The cost of the pension benefits earned by employees in the defined contribution pension plan is paid and expensed when incurred. The cost of the benefits earned by employees in the post-retirement health and dental care plan and defined benefit pension plan is charged to earnings as services are rendered using the projected benefit method prorated on service. The cost of the post-retirement health and dental care plan and defined benefit pension plan reflects a number of assumptions that affect the expected future benefit payments. These assumptions include, but are not limited to, attrition, mortality, the rate of return on pension plan assets and salary escalations for the defined benefit pension plan and expected health care cost trends for the post-retirement health and dental care plan. The plan assets are valued at fair value for the purposes of calculating the expected return on plan assets.
Adjustments arising out of plan amendments, changes in assumptions and experience gains and losses are normally amortized over the expected remaining average service life of the employee group.
Effective July 1, 2007, the Company established a defined benefit pension plan for the employees at the Lima, Ohio refinery. The Company also assumed an unfunded post-retirement welfare plan effective July 1, 2007 that provides life insurance and partially subsidizes the cost of medical benefit premiums. The accounting for the cost of benefits earned by employees covered by these plans is the same as for the Canadian defined benefit pension plan and post-retirement health and dental care plan.
j) Future Income Taxes
The Company follows the liability method of accounting for income taxes. Future income tax assets and liabilities are recognized at expected tax rates in effect when temporary differences between the tax basis and the carrying value of the Company’s assets and liabilities reverse. The effect of a change to the tax rate on the future tax assets and liabilities is recognized in earnings when substantively enacted.
k) Non-monetary Transactions
Non-monetary transactions are measured based on fair value when there is evidence to support the fair value unless the transaction lacks commercial substance or is an exchange of product or property held for sale in the ordinary course of business.
l) Revenue Recognition
Revenues from the sale of crude oil, natural gas, natural gas liquids, synthetic crude oil, purchased commodities and refined petroleum products are recorded when title passes to an external party. Sales between the business segments of the Company are eliminated from sales and operating revenues and cost of sales. Revenues associated with the sale of transportation, processing and natural gas storage services are recognized when the services are provided.
m) Foreign Currency Translation
Results of foreign operations, which are considered financially and operationally integrated, are translated to Canadian dollars at the monthly average exchange rates for revenue and expenses, except for depreciation and depletion which are translated at the rate of exchange applicable to the related assets. Monetary assets and liabilities are translated at current exchange rates and non-monetary assets and liabilities are translated using historical rates of exchange. Gains or losses resulting from these translation adjustments are included in earnings.
The accounts of self-sustaining foreign operations are translated to Canadian dollars using the current rate method. Assets and liabilities are translated at the period-end exchange rate and revenues and expenses are translated at the average exchange rates for the period. Gains and losses on the translation of self-sustaining foreign operations are included in OCI.
n) Stock-based Compensation
In accordance with the Company’s stock option plan, common share options may be granted to officers and certain other employees. The Company records compensation expense over the vesting period based on the fair value of options granted.
The Company’s stock option plan is a tandem plan that provides the stock option holder with the right to exercise the stock option or surrender the option for a cash payment. A liability for expected cash settlements is accrued over the vesting period of the stock options based on the difference between the exercise price of the stock options and the market price of the Company’s common shares. The liability is revalued to reflect changes in
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the market price of the Company’s common shares and the net change is recognized in earnings. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares, consideration paid by the stock option holders and the previously recognized liability associated with the stock options are recorded as share capital. Accrued compensation for an option that is forfeited is adjusted to earnings by decreasing the compensation cost in the period of forfeiture.
o) Earnings per Share
Basic common shares outstanding are the weighted average number of common shares outstanding for each period. The calculation of basic earnings per common share is based on net earnings divided by the weighted average number of common shares outstanding.
Diluted common shares outstanding are calculated using the treasury stock method, which assumes that any proceeds received from in-the-money options would be used to buy back common shares at the average market price for the period. However, since the Company has a tandem stock option plan and accrues a liability for expected cash settlements, the potential common shares issuable upon exercise associated with the stock options are not included in diluted common shares outstanding. Shares potentially issuable on the settlement of the capital securities have not been included in the determination of diluted earnings per common share, as the Company has neither the obligation nor intention to settle amounts due through the issuance of shares.
p) Reclassification
Certain prior years’ amounts have been reclassified to conform with current presentation.
Note 4
Pending Accounting Pronouncements
a) Financial Instruments — Disclosures and Presentation
In December 2006, the Accounting Standards Board (“AcSB”) issued the Canadian Institute of Chartered Accountants (“CICA”) section 3862, “Financial Instruments — Disclosures” and CICA section 3863, “Financial Instruments — Presentation,” which replaces the current CICA section 3861, “Financial Instruments — Disclosure and Presentation.” Section 3862 outlines the disclosure requirements for financial instruments and non-financial derivatives. This guidance prescribes an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. Specifically, section 3862 requires disclosure of the significance of financial instruments for a company’s financial position. In addition, the guidance outlines revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments.
The presentation requirements under section 3863 are relatively unchanged from section 3861. Sections 3862 and 3863 are effective for the Company on January 1, 2008. The Company is currently determining the impact of these additional disclosure requirements.
b) Capital Disclosures
In December 2006, the AcSB issued new CICA section 1535, “Capital Disclosures” requiring disclosures regarding an entity’s objectives, policies and processes for managing capital. These disclosures include a description of what the Company manages as capital, the nature of externally imposed capital requirements, how the requirements are incorporated into the Company’s management of capital, whether the requirements have been complied with, or consequences of non-compliance and an explanation of how the Company is meeting its objectives for managing capital. In addition, quantitative data about capital and whether the Company has complied with all capital requirements are also required. Section 1535 is effective for the Company on January 1, 2008. The Company is currently determining the impact of these additional disclosure requirements.
c) Inventories
In June 2007, the AcSB issued new CICA section 3031, “Inventories,” which replaces the current CICA section 3030 of the same name. The new guidance provides additional measurement and disclosure requirements. Under the new guidance, thelast-in, first-out (LIFO) basis for determining cost will no longer be permitted and reversals of impairment write-downs, which are not currently allowable, will be required. Section 3031 is effective for the Company on January 1, 2008. The transitional provisions of section 3031 provide entities the option of either applying this guidance retrospectively and restating prior periods in accordance with section 1506, “Accounting Changes” or adjusting opening retained earnings and not restating prior periods. The Company has assessed section 3031 and has determined that the adoption of this standard will not have an impact on the financial statements.
Note 5
Accounts Receivable
2007 | 2006 | 2005 | ||||||||||
Trade receivables | $ | 1,599 | $ | 1,286 | $ | 854 | ||||||
Allowance for doubtful accounts | (10 | ) | (10 | ) | (10 | ) | ||||||
Derivatives due within one year | 22 | — | — | |||||||||
Other | 11 | 8 | 12 | |||||||||
$ | 1,622 | $ | 1,284 | $ | 856 | |||||||
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Sale of Accounts Receivable
As at December 31, 2007, the Company’s ceiling on its securitization program to sell, on a revolving basis, accounts receivable to a third party was $350 million. As at December 31, 2007, no accounts receivable had been sold under the program (2006 — nil; 2005 — $350 million). The agreement includes a program fee. The average effective rate for 2007 was approximately 5.3% (2006 — 4.1%; 2005 - 3.0%).
Proceeds from revolving sales between the third party and the Company in 2007 totalled approximately $3.5 billion (2006 — $3.1 billion; 2005 — $3.4 billion).
Note 6
Inventories
2007 | 2006 | 2005 | ||||||||||
Crude oil | $ | 539 | $ | 119 | $ | 167 | ||||||
Natural gas | 192 | 193 | 207 | |||||||||
Refined petroleum products | 409 | 89 | 74 | |||||||||
Materials, supplies and other | 50 | 27 | 23 | |||||||||
$ | 1,190 | $ | 428 | $ | 471 | |||||||
Note 7
Property, Plant and Equipment
Refer to note 1, Segmented Financial Information, which presents the Company’s property, plant and equipment by segment.
Administrative costs related to exploration and development activities capitalized in 2007 were $48 million (2006 — $68 million; 2005 — $61 million).
Costs of oil and gas properties, including major development projects, excluded from costs subject to depletion and depreciation at December 31 were as follows:
2007 | 2006 | 2005 | ||||||||||
Canada | $ | 1,954 | $ | 1,932 | $ | 2,317 | ||||||
International | 243 | 165 | 127 | |||||||||
$ | 2,197 | $ | 2,097 | $ | 2,444 | |||||||
The prices used in the ceiling test evaluation of the Company’s crude oil and natural gas reserves at December 31, 2007 were:
Price increase | ||||||||||||||||||||||||
Canada | 2008 | 2009 | 2010 | 2011 | 2012 | 2012 to 2027 | ||||||||||||||||||
(percent) | ||||||||||||||||||||||||
Crude oil($/bbl) | $ | 61.56 | $ | 55.73 | $ | 51.07 | $ | 48.13 | $ | 46.99 | 3 | |||||||||||||
Natural gas($/mcf) | 6.59 | 6.72 | 6.63 | 6.73 | 6.86 | 2 |
Note 8
Corporate Acquisition
In July 2007, the Company acquired a refinery in Lima, Ohio from The Premcor Refining Group Inc., an indirect wholly owned subsidiary of Valero Energy Corporation through the purchase of all of the issued and outstanding shares of Lima Refining Company (“Lima”). The total cash consideration was U.S. $1.9 billion plus U.S. $540 million for the cost of feedstock and product inventory. The results of Lima are included in the consolidated financial statements of the Company from its acquisition date. The Lima operations have been included in the Downstream — U.S. Refining and Marketing segment in note 1, Segmented Financial Information. The operations of Lima are a self-sustaining foreign operation for foreign currency translation purposes.
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The allocation of the aggregate purchase price based on the estimated fair values of the net assets of Lima on its acquisition date was as follows:
U.S. $ | Cdn $ | |||||||
Net assets acquired | ||||||||
Working capital | $ | 4 | $ | 4 | ||||
Property, plant and equipment | 1,455 | 1,542 | ||||||
Goodwill(1) | 506 | 536 | ||||||
Other assets | 25 | 26 | ||||||
Other long-term liabilities | (86 | ) | (91 | ) | ||||
1,904 | 2,017 | |||||||
Feedstock and product inventory acquired | 540 | 572 | ||||||
Total | $ | 2,444 | $ | 2,589 | ||||
(1) | Allocated to U.S. Refining and Marketing in the Company’s downstream segment. For U.S. income tax purposes, goodwill is deductible and amortized over a15-year period. Refer to note 1, Segmented Financial Information. |
Note 9
Cash Flows — Change in Non-cash Working Capital
a) Change in non-cash working capital was as follows:
2007 | 2006 | 2005 | ||||||||||
Decrease (increase) in non-cash working capital | ||||||||||||
Accounts receivable | $ | (345 | ) | $ | (428 | ) | $ | (410 | ) | |||
Inventories | (212 | ) | 43 | (197 | ) | |||||||
Prepaid expenses | 1 | 14 | 17 | |||||||||
Accounts payable and accrued liabilities | (190 | ) | 277 | 962 | ||||||||
Change in non-cash working capital | $ | (746 | ) | $ | (94 | ) | $ | 372 | ||||
Relating to: | ||||||||||||
Operating activities | $ | (718 | ) | $ | 544 | $ | (94 | ) | ||||
Financing activities | 65 | (678 | ) | 255 | ||||||||
Investing activities | (93 | ) | 40 | 211 | ||||||||
b) Other cash flow information:
2007 | 2006 | 2005 | ||||||||||
Cash taxes paid | $ | 926 | $ | 215 | $ | 154 | ||||||
Cash interest paid | 162 | 147 | 147 |
Note 10
Bank Operating Loans
At December 31, 2007, the Company had unsecured short-term borrowing lines of credit with banks totalling $270 million (2006 — $220 million; 2005 — $195 million). As at December 31, 2007, bank operating loans (excluding reclassified outstanding cheques) were nil (2006 — nil; 2005 — $0.4 million) and letters of credit under these lines of credit totalled $73 million (2006 — $19 million; 2005 — $18 million). Interest payable is based on Bankers’ Acceptance, U.S. LIBOR or prime rates. During 2007, the weighted average interest rate on short-term borrowings was approximately 5.8% (2006 — 5.8%; 2005 — 3.9%).
Note 11
Accounts Payable and Accrued Liabilities
2007 | 2006 | 2005 | ||||||||||
Trade payables | $ | 23 | $ | 74 | $ | 7 | ||||||
Accrued liabilities | 1,743 | 1,322 | 1,338 | |||||||||
Dividend payable | 280 | 212 | 530 | |||||||||
Stock-based compensation | 159 | 234 | 130 | |||||||||
Current income taxes | 36 | 615 | 164 | |||||||||
Other | 117 | 117 | 141 | |||||||||
$ | 2,358 | $ | 2,574 | $ | 2,310 | |||||||
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Note 12
Long-term Debt
Cdn $ Amount | U.S. $ Denominated | |||||||||||||||||||||||||||
Maturity | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||||||
Long-term debt | ||||||||||||||||||||||||||||
6.85% medium-term notes — Series B | 2007 | $ | — | $ | — | $ | 100 | $ | — | $ | — | $ | — | |||||||||||||||
6.95% medium-term notes — Series E | 2009 | 203 | 200 | 200 | — | — | — | |||||||||||||||||||||
6.25% notes | 2012 | 395 | 466 | 467 | 400 | 400 | 400 | |||||||||||||||||||||
7.55% debentures | 2016 | 198 | 233 | 233 | 200 | 200 | 200 | |||||||||||||||||||||
6.20% notes | 2017 | 296 | — | — | 300 | — | — | |||||||||||||||||||||
6.15% notes | 2019 | 296 | 350 | 350 | 300 | 300 | 300 | |||||||||||||||||||||
8.90% capital securities | 2028 | 223 | 262 | 262 | 225 | 225 | 225 | |||||||||||||||||||||
6.80% notes | 2037 | 445 | — | — | 450 | — | — | |||||||||||||||||||||
Debt issue costs | (20 | ) | — | — | — | — | — | |||||||||||||||||||||
Unwound interest rate swaps | 37 | — | — | — | — | — | ||||||||||||||||||||||
$ | 2,073 | $ | 1,511 | $ | 1,612 | $ | 1,875 | $ | 1,125 | $ | 1,125 | |||||||||||||||||
Long-term debt due within one year | ||||||||||||||||||||||||||||
Bridge financing | 2008 | $ | 741 | $ | — | $ | — | $ | 750 | $ | — | $ | — | |||||||||||||||
6.85% medium-term notes — Series B | 2007 | — | 100 | — | — | — | — | |||||||||||||||||||||
7.125% notes | 2006 | — | — | 175 | — | — | 150 | |||||||||||||||||||||
8.45% senior secured bonds | 2006 | — | — | 99 | — | — | 85 | |||||||||||||||||||||
$ | 741 | $ | 100 | $ | 274 | $ | 750 | $ | — | $ | 235 | |||||||||||||||||
Interest — net for the years ended December 31 was as follows:
2007 | 2006 | 2005 | ||||||||||
Long-term debt | $ | 151 | $ | 130 | $ | 144 | ||||||
Short-term debt | 6 | 5 | 4 | |||||||||
157 | 135 | 148 | ||||||||||
Amount capitalized | (19 | ) | (33 | ) | (114 | ) | ||||||
138 | 102 | 34 | ||||||||||
Interest income | (8 | ) | (10 | ) | (2 | ) | ||||||
$ | 130 | $ | 92 | $ | 32 | |||||||
Foreign exchange for the years ended December 31 was as follows:
2007 | 2006 | 2005 | ||||||||||
Gain on translation of U.S. dollar denominated long-term debt | $ | (197 | ) | $ | (7 | ) | $ | (51 | ) | |||
Cross currency swaps | 62 | 4 | 14 | |||||||||
Other (gains) losses | 84 | (21 | ) | 6 | ||||||||
$ | (51 | ) | $ | (24 | ) | $ | (31 | ) | ||||
Credit Facilities
The revolving syndicated credit facility allows the Company to borrow up to $1.25 billion in either Canadian or U.S. currency from a group of banks on an unsecured basis. The facility is structured as a five-year committed revolving credit facility. Interest rates vary based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected and credit ratings assigned by certain credit rating agencies to the Company’s rated senior unsecured debt.
The Company’s $150 million revolving bilateral credit facilities have substantially the same terms as the syndicated credit facility.
In July 2007, the Company obtained U.S. $1.5 billion of short-term bridge financing at an interest rate based on U.S. LIBOR, maturing June 26, 2008, to facilitate closing the acquisition of the Lima, Ohio refinery. On September 11, 2007, the Company refinanced U.S. $750 million with long-term notes. The Company has the right to extend the remaining bridge financing of U.S. $750 million to June 26, 2009 by providing 30 days’ notice.
As at December 31, 2007, there were no borrowings under the syndicated credit facility or the bilateral credit facilities.
Notes and Debentures
On September 21, 2006, Husky filed a shelf prospectus, which enables Husky to offer up to U.S. $1.0 billion of debt securities in the United States until October 21, 2008. During the25-month period that the prospectus remains effective, debt securities may be offered in amounts, at prices and on terms to be determined based on market conditions at the time of sale and set forth in an accompanying prospectus supplement. In 2007, U.S. $750 million of debt securities were issued under this new shelf prospectus.
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The medium-term notes Series E represent unsecured securities under a trust indenture dated May 4, 1999. Interest is payable semi-annually.
The 6.25% and the 6.15% notes represent unsecured securities under a trust indenture dated June 14, 2002. Interest is payable semi-annually.
The 7.55% debentures represent unsecured securities under a trust indenture dated October 31, 1996. Interest is payable semi-annually.
The 6.20% and the 6.80% notes represent unsecured securities under a trust indenture dated September 11, 2007. Interest is payable semi-annually.
The 8.90% capital securities represent unsecured securities under an indenture dated August 10, 1998. Such securities rank junior to all senior debt and other financial debt of the Company. The 8.90% interest is payable semi-annually until August 15, 2008. The capital securities mature in 2028. They are redeemable, in whole or in part, by the Company at any time prior to August 15, 2008 at a redemption price equal to the greater of the par value of the securities and the sum of the present values of the remaining scheduled payments discounted at a rate calculated using a comparable U.S. Treasury Bond rate plus an applicable spread. They are redeemable at par, in whole but not in part, by the Company on or after August 15, 2008. If not redeemed in whole, commencing on August 15, 2008, the interest rate changes to a floating rate equal to U.S. LIBOR plus 5.50% payable semi-annually. The Company has the right at any time prior to maturity, subject to certain conditions, to defer payment of interest for up to five years. The Company also has the unrestricted ability to settle its deferred interest, principal and redemption obligations through the issuance of common or preferred shares.
The medium-term notes Series B represented unsecured securities under a trust indenture dated February 3, 1997 and matured in 2007.
The 7.125% notes represented unsecured securities under a trust indenture dated October 31, 1996 and matured in 2006. Interest was payable semi-annually.
The 8.45% senior secured bonds represented securities under a trust indenture dated July 20, 1999 that were redeemed in full on February 1, 2006. Interest was payable semi-annually. Certain related financial obligations required collateral of letters of creditand/or cash equivalents. As at December 31, 2005, letters of credit totalling $41 million were outstanding.
The notes and debentures disclosed above are redeemable (unless otherwise stated) at the option of the Company, at any time, at a redemption price equal to the greater of the par value of the securities and the sum of the present values of the remaining scheduled payments discounted at a rate calculated using a comparable U.S. Treasury Bond rate (for U.S. dollar denominated securities) or Government of Canada Bond rate (for Canadian dollar denominated securities) plus an applicable spread.
Commencing in 2007, debt issue costs have been reclassified to long-term debt with the adoption of CICA section 3855, “Financial Instruments — Recognition and Measurement” (refer to notes 3 and 19). Previously, these deferred costs were included in other assets. As at December 31, 2006 and 2005, other assets included $12 million and $21 million of deferred debt issue costs, respectively.
The unamortized portion of the gain on previously unwound interest rate swaps that would be designated as fair value hedges is included in the carrying value of long-term debt with the adoption of Financial Instruments.
Note 13
Other Long-term Liabilities
2007 | 2006 | 2005 | ||||||||||
Asset retirement obligations | $ | 662 | $ | 622 | $ | 557 | ||||||
Cross currency swaps(1) | 107 | 40 | 40 | |||||||||
Interest rate swaps | — | 37 | 42 | |||||||||
Employee future benefits | 69 | 30 | 27 | |||||||||
Capital lease | 36 | — | — | |||||||||
Stock-based compensation | 13 | 4 | 46 | |||||||||
Other | 31 | 23 | 18 | |||||||||
$ | 918 | $ | 756 | $ | 730 | |||||||
(1) | Refer to note 19, Financial Instruments and Risk Management. |
Asset Retirement Obligations
At December 31, 2007, the estimated total undiscounted inflation adjusted amount required to settle the asset retirement obligations was $4.7 billion. These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 30 years into the future. This amount has been discounted using credit adjusted risk free rates ranging from 6.2% to 6.8%.
Changes to the asset retirement obligations were as follows:
2007 | 2006 | 2005 | ||||||||||
Asset retirement obligations at beginning of year | $ | 622 | $ | 557 | $ | 509 | ||||||
Liabilities incurred | 57 | 35 | 63 | |||||||||
Liabilities disposed | (13 | ) | (1 | ) | (7 | ) | ||||||
Liabilities settled | (51 | ) | (36 | ) | (41 | ) | ||||||
Revisions | — | 22 | — | |||||||||
Accretion(1) | 47 | 45 | 33 | |||||||||
Asset retirement obligations at end of year | $ | 662 | $ | 622 | $ | 557 | ||||||
(1) | Accretion is included in cost of sales and operating expenses. |
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Note 14
Income Taxes
The provision for income taxes in the Consolidated Statements of Earnings and Comprehensive Income reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31 were accounted for as follows:
2007 | 2006 | 2005 | ||||||||||
Earnings (loss) before income taxes | ||||||||||||
Canada | $ | 3,763 | $ | 3,276 | $ | 2,553 | ||||||
United States | 95 | 15 | (6 | ) | ||||||||
Other foreign jurisdictions | 269 | 215 | 265 | |||||||||
4,127 | 3,506 | 2,812 | ||||||||||
Statutory income tax rate(percent) | 32.7 | 35.7 | 38.4 | |||||||||
Expected income tax | 1,350 | 1,252 | 1,080 | |||||||||
Effect on income tax of: | ||||||||||||
Royalties, lease rentals and mineral taxes payable to the crown | — | 10 | 105 | |||||||||
Resource allowance on Canadian production income | — | (35 | ) | (133 | ) | |||||||
Change in statutory tax rate | (395 | ) | (328 | ) | (4 | ) | ||||||
Rate benefit on partnership earnings | (53 | ) | (97 | ) | (69 | ) | ||||||
Capital gains and losses | (24 | ) | (1 | ) | (140 | ) | ||||||
Foreign jurisdictions | 8 | (6 | ) | (14 | ) | |||||||
Non-deductible capital taxes | — | (17 | ) | 15 | ||||||||
Other — net | 27 | 2 | (31 | ) | ||||||||
Income tax expense | $ | 913 | $ | 780 | $ | 809 | ||||||
During 2007, a tax benefit of $395 million was recognized as a result of reductions in the Canadian federal tax rate, compared with a benefit of $328 million in 2006 as a result of reductions in both federal and provincial tax rates.
The future income tax liability at December 31 comprised the tax effect of temporary differences as follows:
2007 | 2006 | 2005 | ||||||||||
Future tax liabilities | ||||||||||||
Property, plant and equipment | $ | 4,081 | $ | 3,607 | $ | 3,487 | ||||||
Foreign exchange gains taxable on realization | 131 | 48 | 60 | |||||||||
Other temporary differences | 1 | 1 | 2 | |||||||||
4,213 | 3,656 | 3,549 | ||||||||||
Future tax assets | ||||||||||||
Asset retirement obligations | 186 | 194 | 195 | |||||||||
Loss carry forwards | — | 2 | — | |||||||||
Provincial royalty rebates | — | 2 | 7 | |||||||||
Other temporary differences | 70 | 86 | 77 | |||||||||
256 | 284 | 279 | ||||||||||
$ | 3,957 | $ | 3,372 | $ | 3,270 | |||||||
Note 15
Commitments and Contingencies
Certain former owners of interests in the upgrading assets retained a20-year upside financial interest expiring in 2014 which requires payments to them when the average differential between heavy crude oil feedstock and synthetic crude oil exceeds $6.50 per barrel. The calculation is based on a two-year rolling average of the differential. During 2007, the Company capitalized $84 million (2006 — $85 million; 2005 — $68 million) of payments under this arrangement.
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At December 31, 2007, the Company had commitments for non-cancellable operating leases and other long-term agreements that require the following minimum future payments:
After | ||||||||||||||||||||||||||||
2008 | 2009 | 2010 | 2011 | 2012 | 2012 | Total | ||||||||||||||||||||||
Long-term debt and interest | $ | 1,104 | $ | 323 | $ | 106 | $ | 107 | $ | 488 | $ | 2,254 | $ | 4,382 | ||||||||||||||
Operating leases | 218 | 285 | 268 | 161 | 64 | 28 | 1,024 | |||||||||||||||||||||
Firm transportation agreements | 165 | 100 | 68 | 36 | 33 | 147 | 549 | |||||||||||||||||||||
Unconditional purchase obligations | 2,564 | 1,189 | 283 | 115 | 46 | 39 | 4,236 | |||||||||||||||||||||
Lease rentals and exploration work agreements | 175 | 105 | 121 | 141 | 91 | 215 | 848 | |||||||||||||||||||||
Engineering and construction commitments | 71 | — | — | — | — | — | 71 | |||||||||||||||||||||
$ | 4,297 | $ | 2,002 | $ | 846 | $ | 560 | $ | 722 | $ | 2,683 | $ | 11,110 | |||||||||||||||
The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position, results of operations or liquidity. In 2005 a lawsuit was settled with proceeds received and the resulting gain was recognized in earnings and recorded in other — net.
The Company has income tax filings that are subject to audit and potential reassessment. The findings may impact the tax liability of the Company. The final results are not reasonably determinable at this time and management believes that it has adequately provided for current and future income taxes.
Note 16
Share Capital
The Company’s authorized share capital is as follows:
Common shares — an unlimited number of no par value.
Preferred shares — an unlimited number of no par value, none outstanding.
Common Shares
On June 27, 2007, the Company filed Articles of Amendment to implement a two-for-one share split of its issued and outstanding common shares. The share split was approved at a special meeting of the shareholders on June 27, 2007. All references to common share amounts, including common shares issued and outstanding, basic and diluted earnings per share, dividend per share, weighted average number of common shares outstanding, stock options granted, exercised, surrendered and forfeited, Renaissance Energy Ltd. (“Renaissance”) replacement options and warrants granted and exercised have been retroactively restated to reflect the impact of the two-for-one share split. Changes to issued share capital were as follows:
Number of Shares | Amount | |||||||
December 31, 2004 | 847,472,828 | $ | 3,506 | |||||
Options and warrants exercised | 777,328 | 17 | ||||||
December 31, 2005 | 848,250,156 | 3,523 | ||||||
Options exercised | 286,862 | 10 | ||||||
December 31, 2006 | 848,537,018 | 3,533 | ||||||
Options exercised | 423,292 | 18 | ||||||
December 31, 2007 | 848,960,310 | $ | 3,551 | |||||
Stock Options
At December 31, 2007, 55.0 million common shares were reserved for issuance under the Company stock option plan. The stock option plan is a tandem plan that provides the stock option holder with the right to exercise the option or surrender the option for a cash payment. The exercise price of the option is equal to the weighted average trading price of the Company’s common shares during the five trading days prior to the date of the award. When the option is surrendered for cash, the cash payment is the difference between the weighted average trading price of the Company’s common shares on the trading day prior to the surrender date and the exercise price of the option.
Under the terms of the original stock option plan, the options awarded have a maximum term of five years and vest over three years on the basis of one-third per year. Effective February 26, 2007, the Board of Directors approved amendments to the Company’s stock option plan to also provide for performance vesting of stock options. Shareholder ratification was obtained at the Annual and Special Meeting of Shareholders on April 19, 2007. Performance options granted may vest in up to one-third increments if the Company’s annual total shareholder return (stock price appreciation and cumulative dividends on a reinvested basis) falls within certain percentile ranks relative to its industry peer group. The ultimate number of performance options that vest will depend upon the Company’s performance measured over three calendar years. If the Company’s performance is below the specified level compared with its industry peer group, the performance options awarded will be forfeited. If the Company’s performance is at or above the specified level compared with its industry peer group, the number of performance options exercisable shall be determined by the Company’s relative ranking. Stock compensation expense related to the performance options is accrued based on the price of the common shares at the end of the period and the anticipated performance factor. This expense is recognized over the three-year vesting period of the performance options. During 2007, $12.2 million of expense was recognized related to the performance options.
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As a result of the special $0.25 per share dividend that was declared in February 2007, a downward adjustment of $0.175 was made to the exercise price of all outstanding stock options effective February 28, 2007, in accordance with the terms of the stock option plan under which the options were issued. In 2005, a similar downward adjustment of $0.275 was made to the exercise price of all outstanding stock options as a result of a special $0.50 dividend declared in that year.
The following options to purchase common shares have been awarded to officers and certain other employees:
Number of | Weighted | Weighted Average | Options | |||||||||||||
Options | Average | Contractual | Exercisable | |||||||||||||
(thousands) | Exercise Prices | Life (years) | (thousands) | |||||||||||||
December 31, 2004 | 19,929 | $ | 11.30 | 4 | 2,834 | |||||||||||
Granted | 1,339 | $ | 24.07 | 5 | ||||||||||||
Exercised for common shares | (718 | ) | $ | 7.92 | 1 | |||||||||||
Surrendered for cash | (4,886 | ) | $ | 9.52 | 2 | |||||||||||
Forfeited | (1,094 | ) | $ | 12.05 | 3 | |||||||||||
December 31, 2005 | 14,570 | $ | 12.91 | 3 | 3,066 | |||||||||||
Granted | 1,804 | $ | 35.71 | 4 | ||||||||||||
Exercised for common shares | (287 | ) | $ | 11.15 | 2 | |||||||||||
Surrendered for cash | (3,902 | ) | $ | 11.97 | 2 | |||||||||||
Forfeited | (529 | ) | $ | 21.41 | 3 | |||||||||||
December 31, 2006 | 11,656 | $ | 16.40 | 3 | 4,463 | |||||||||||
Granted | 26,926 | $ | 41.65 | 4 | ||||||||||||
Exercised for common shares | (423 | ) | $ | 11.84 | 1 | |||||||||||
Surrendered for cash | (5,147 | ) | $ | 13.40 | 2 | |||||||||||
Forfeited | (2,881 | ) | $ | 40.41 | 4 | |||||||||||
December 31, 2007 | 30,131 | $ | 37.18 | 4 | 4,494 | |||||||||||
As at December 31, 2007 | Outstanding Options | Options Exercisable | ||||||||||||||||||
Number of | Weighted | Weighted Average | Number of | Weighted | ||||||||||||||||
Options | Average | Contractual | Options | Average | ||||||||||||||||
Range of Exercise Price | (thousands) | Exercise Prices | Life (years) | (thousands) | Exercise Prices | |||||||||||||||
$7.23 - $9.99 | 44 | $ | 7.26 | — | 44 | $ | 7.26 | |||||||||||||
$10.00 - $10.99 | 27 | $ | 10.32 | 1 | 27 | $ | 10.32 | |||||||||||||
$11.00 - $12.99 | 3,832 | $ | 11.74 | 1 | 3,832 | $ | 11.74 | |||||||||||||
$13.00 - $19.99 | 130 | $ | 15.92 | 2 | 84 | $ | 15.39 | |||||||||||||
$20.00 - $29.99 | 455 | $ | 26.17 | 3 | 205 | $ | 26.43 | |||||||||||||
$30.00 - $39.99 | 1,258 | $ | 35.89 | 3 | 302 | $ | 36.46 | |||||||||||||
$40.00 - $42.57 | 24,385 | $ | 41.65 | 4 | — | $ | — | |||||||||||||
30,131 | $ | 37.18 | 4 | 4,494 | $ | 14.09 | ||||||||||||||
Warrants
In 2000, the Company granted 2.7 million Renaissance replacement options to purchase common shares of Husky in exchange for certain share purchase options to purchase common shares of Renaissance previously held by employees of Renaissance. The former shareholders of Husky Oil Limited were also granted warrants to acquire, for no additional consideration, 1.86 common shares of the Company for each common share issued on the exercise of a Renaissance replacement option. As at December 31, 2007, 2006 and 2005, there were no Renaissance replacement options or warrants outstanding. During 2005, 32,000 warrants were exercised.
Dividends
During 2007, the Company declared dividends of $1.33 per common share (2006 — $0.75 per common share; 2005 — $0.825 per common share), including special dividends of $0.25 per common share in 2007 and $0.50 per common share in 2005.
Note 17
Employee Future Benefits
a) Canada
The Company currently provides a defined contribution pension plan for all qualified employees. The Company also maintains a defined benefit pension plan, which is closed to new entrants, and all current participants are vested. The Company also provides certain health and dental coverage to its retirees, which is accrued over the expected average remaining service life of the employees.
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Defined Benefit Pension Plan
Weighted average long-term assumptions are based on independent historical and projected references and are noted below:
2007 | 2006 | 2005 | ||||||||||
Discount rate(percent) | 5.0 | 5.0 | 5.8 | |||||||||
Long-term rate of increase in compensation levels(percent) | 5.0 | �� | 5.0 | 5.0 | ||||||||
Long-term rate of return on plan assets(percent) | 7.5 | 7.5 | 7.5 |
The discount rate used at the end of 2007 to determine the accrued benefit obligation was 5%.
The long-term rate of return on the assets was determined based on management’s best estimate and the historical rates of return, adjusted periodically. The rate at the end of 2007 was 7.5%.
The status of the defined benefit pension plan at December 31 was as follows:
Benefit Obligation
2007 | 2006 | 2005 | ||||||||||
Benefit obligation, beginning of year | $ | 149 | $ | 138 | $ | 124 | ||||||
Current service cost | 2 | 3 | 2 | |||||||||
Interest cost | 7 | 7 | 7 | |||||||||
Benefits paid | (8 | ) | (7 | ) | (6 | ) | ||||||
Actuarial losses | — | 8 | 11 | |||||||||
Benefit obligation, end of year | $ | 150 | $ | 149 | $ | 138 | ||||||
Fair Value of Plan Assets
2007 | 2006 | 2005 | ||||||||||
Fair value of plan assets, beginning of year | $ | 132 | $ | 108 | $ | 96 | ||||||
Contributions | 10 | 13 | 11 | |||||||||
Benefits paid | (8 | ) | (7 | ) | (6 | ) | ||||||
Expected return on plan assets | 10 | 8 | 7 | |||||||||
Gain on plan assets | (3 | ) | 10 | — | ||||||||
Fair value of plan assets, end of year | $ | 141 | $ | 132 | $ | 108 | ||||||
Funded Status of Plan
2007 | 2006 | 2005 | ||||||||||
Fair value of plan assets | $ | 141 | $ | 132 | $ | 108 | ||||||
Benefit obligation | (150 | ) | (149 | ) | (138 | ) | ||||||
Excess obligation | (9 | ) | (17 | ) | (30 | ) | ||||||
Unrecognized past service costs | 3 | 3 | 1 | |||||||||
Unrecognized losses | 32 | 33 | 40 | |||||||||
Accrued benefit asset | $ | 26 | $ | 19 | $ | 11 | ||||||
Husky adheres to a Statement of Investment Policies and Procedures (the “Policy”). The assets are allocated in accordance with the long-term nature of the obligation and comprise a balanced investment based on interest rate and inflation sensitivities. The Policy explicitly prescribes diversification parameters for all classes of investment.
The Company’s actuaries perform valuations as at December 31 for the defined benefit pension plan. The last actuarial valuation was conducted in 2007 and the next valuation will be conducted in 2008.
The composition of the defined benefit pension plan assets was as follows:
2007 | 2006 | 2005 | ||||||||||
U.S. common equities | 1 | % | 1 | % | — | % | ||||||
Canadian common equities | 30 | 30 | 29 | |||||||||
International equity mutual funds | 27 | 30 | 28 | |||||||||
Canadian government bonds | 14 | 16 | 18 | |||||||||
Canadian corporate bonds | 4 | 3 | 3 | |||||||||
International fixed income | 2 | — | — | |||||||||
Canadian fixed income mutual funds | 20 | 19 | 20 | |||||||||
Cash and receivables | 2 | 1 | 2 | |||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||
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During 2007, Husky contributed $10 million to the defined benefit pension plan assets, $8 million of which was in respect of additional contributions as a result of the plan’s deficiency. Husky currently plans to contribute $6 million in 2008.
The Company amortizes the portion of the unrecognized actuarial gains or losses that exceed 10% of the greater of the accrued benefit obligation or the market-related value of pension plan assets. The market-related value of pension plan assets is the fair value of the assets. The gains or losses that are in excess of 10% are amortized over the expected future years of service, which is currently seven years.
The past service costs are amortized over the expected future years of service.
Post-retirement Health and Dental Care Plan
The discount rate used in the calculation of the benefit obligation was 5%. The average health care cost trend used was 9.5% which is reduced by 0.50% until 2015. The average dental care cost trend used was 4%, which remains constant.
The status of the post-retirement health and dental care plan at December 31 was as follows:
Benefit Obligation
2007 | 2006 | 2005 | ||||||||||
Benefit obligation, beginning of year | $ | 49 | $ | 33 | $ | 25 | ||||||
Current service cost | 4 | 2 | 2 | |||||||||
Interest cost | 2 | 2 | 1 | |||||||||
Benefits paid | (1 | ) | — | — | ||||||||
Actuarial losses | — | 12 | 5 | |||||||||
Benefit obligation, end of year | $ | 54 | $ | 49 | $ | 33 | ||||||
Funded Status of Plan
2007 | 2006 | 2005 | ||||||||||
Benefit obligation | $ | (54 | ) | $ | (49 | ) | $ | (33 | ) | |||
Unrecognized losses | 17 | 19 | 6 | |||||||||
Accrued benefit liability | $ | (37 | ) | $ | (30 | ) | $ | (27 | ) | |||
The assumed health care cost trend can have a significant effect on the amounts reported for Husky’s post-retirement health and dental care plan. A one percent increase and decrease in the assumed trend rate would have the following effect:
1% | 1% | |||||||
Increase | Decrease | |||||||
Effect on total service and interest cost components | $ | 2 | $ | (1 | ) | |||
Effect on post-retirement benefit obligation | $ | 12 | $ | (9 | ) |
Pension Expense and Post-retirement Health and Dental Care Expense
The expenses for the years ended December 31 were as follows:
Pension Expense
2007 | 2006 | 2005 | ||||||||||
Defined benefit pension plan | ||||||||||||
Employer current service cost | $ | 2 | $ | 3 | $ | 2 | ||||||
Interest cost | 7 | 7 | 7 | |||||||||
Expected return on plan assets | (10 | ) | (8 | ) | (7 | ) | ||||||
Amortization of net actuarial losses | 3 | 3 | 3 | |||||||||
2 | 5 | 5 | ||||||||||
Defined contribution pension plan | 18 | 16 | 14 | |||||||||
Total expense | $ | 20 | $ | 21 | $ | 19 | ||||||
Post-retirement Health and Dental Care Expense
2007 | 2006 | 2005 | ||||||||||
Employer current service cost | $ | 4 | $ | 2 | $ | 2 | ||||||
Interest cost | 2 | 2 | 1 | |||||||||
Amortization of net actuarial losses | 1 | — | — | |||||||||
Total expense | $ | 7 | $ | 4 | $ | 3 | ||||||
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Future Benefit Payments
The following table discloses the current estimate of future benefit payments:
Defined Benefit | Post-retirement Health | |||||||
Pension Plan | and Dental Care Plan | |||||||
2008 | $ | 8 | $ | 1 | ||||
2009 | 9 | 1 | ||||||
2010 | 9 | 1 | ||||||
2011 | 9 | 1 | ||||||
2012 | 10 | 2 | ||||||
2013 - 2017 | 52 | 10 |
b) United States
Defined Benefit Pension Plan
As at December 31, 2007, the benefit obligation was $1 million and the fair value of the plan assets was $1 million. The discount rate used at the end of 2007 to determine the accrued benefit obligation was 6.10%. During 2007, Husky contributed $1 million to the defined benefit pension plan assets and currently plans to contribute $2 million in 2008.
Pension expense for the six months ended December 31, 2007 was $1 million.
Post-retirement Welfare Plan
As at December 31, 2007, the benefit obligation was $33 million. The discount rate used at the end of 2007 to determine the accrued benefit obligation was 6.25%.
Post-retirement welfare expense for the six months ended December 31, 2007 was $1.5 million.
Note 18
Related Party Transactions
During the year, TransAlta Power, L.P. (“TAPLP”) came under the indirect control of Husky’s principal shareholders. TAPLP is a 49.99% owner in TransAlta Cogeneration, L.P. (“TACLP”) which is the Company’s joint venture partner for the Meridian cogeneration facility at Lloydminster. The Company sells natural gas to the Meridian cogeneration facility and other cogeneration facilities owned by TACLP. These natural gas sales are related party transactions and have been measured at the exchange amount. For 2007, the total value of natural gas sales to the Meridian and other cogeneration facilities owned by TACLP was $104 million. At December 31, 2007, the total value of accounts receivables related to these transactions was $10 million.
Note 19
Financial Instruments and Risk Management
Effective January 1, 2007, the Company adopted CICA section 3855, “Financial Instruments — Recognition and Measurement,” section 3865, “Hedges,” section 1530, “Comprehensive Income” and section 3861, “Financial Instruments — Disclosure and Presentation.” The Company has adopted these standards prospectively and the comparative consolidated financial statements have not been restated. Transition amounts have been recorded in retained earnings or accumulated other comprehensive income.
Upon adoption and with any new financial instrument, an irrevocable election was available to classify any financial asset or financial liability as held for trading, even if the financial instrument did not meet the criteria to designate it as held for trading. The Company did not elect to classify any financial assets or financial liabilities as held for trading unless they met the held for trading criteria.
The following table summarizes the prospective adoption adjustments that were required as at January 1, 2007:
December 31, 2006 | Adoption | January 1, 2007 | ||||||||||
(As Reported) | Adjustment | (As Restated) | ||||||||||
Consolidated Balance Sheets | ||||||||||||
Assets | ||||||||||||
Accounts receivable | $ | 1,284 | $ | 6 | $ | 1,290 | ||||||
Prepaid expenses | 25 | (2 | ) | 23 | ||||||||
Other assets | 44 | (7 | ) | 37 | ||||||||
Liabilities and Shareholders’ Equity | ||||||||||||
Accounts payable and accrued liabilities | 2,574 | (5 | ) | 2,569 | ||||||||
Long-term debt due within one year | 100 | (2 | ) | 98 | ||||||||
Long-term debt | 1,511 | 34 | 1,545 | |||||||||
Other long-term liabilities | 756 | (10 | ) | 746 | ||||||||
Future income taxes | 3,372 | (6 | ) | 3,366 | ||||||||
Retained earnings | 6,087 | 4 | 6,091 | |||||||||
Accumulated other comprehensive income | — | (18 | ) | (18 | ) |
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Carrying Values and Estimated Fair Values of Financial Assets and Liabilities
The carrying value of cash and cash equivalents, accounts receivable, bank operating loans, accounts payable and accrued liabilities approximates their fair value due to the short-term maturity of these instruments.
The fair value of long-term debt is the present value of future cash flows associated with the debt. Market information such as treasury rates and credit spreads is used to determine the appropriate discount rates. The estimated fair value of long-term debt at December 31 was as follows:
2007 | 2006 | 2005 | ||||||||||||||||||||||
Carrying | Fair | Carrying | Fair | Carrying | Fair | |||||||||||||||||||
Value | Value | Value | Value | Value | Value | |||||||||||||||||||
Long-term debt | $ | 2,814 | $ | 2,903 | $ | 1,611 | $ | 1,671 | $ | 1,886 | $ | 1,995 |
Commodity Price Risk Management
Natural Gas Contracts
The Company has a portfolio of fixed and basis price offsetting physical forward purchase and sale natural gas contracts relating to marketing of other producers’ natural gas. The objective of these contracts is to “lock in” a positive spread between the physical purchase and sale contract prices. At December 31, 2007, the Company had the following third party offsetting physical purchase and sale natural gas contracts, which met the definition of a derivative instrument:
Volumes | Fair | |||||||
(mmcf) | Value | |||||||
Physical purchase contracts | 32,930 | $ | 6 | |||||
Physical sale contracts | (32,930 | ) | $ | (5 | ) |
These contracts have been recorded at their fair value in accounts receivable and the resulting unrealized gain has been recorded in other expenses in the consolidated statement of earnings for the period.
Natural Gas Production
The Company did not have a natural gas hedge program in 2007 or 2006. In 2005, the Company realized a loss of $17 million related to these natural gas contracts.
Power Consumption
In 2007, the Company realized a loss of less than $1 million (2006 — gain of $6 million; 2005 — gain of $4 million) on hedged power consumption.
Interest Rate Risk Management
The majority of the Company’s long-term debt has fixed interest rates and various maturities. The Company periodically uses interest rate swaps to manage its financing costs. At December 31, 2007, the Company had entered into a fair value hedge using interest rate swap arrangements whereby the fixed interest rate coupon on the medium-term notes was swapped to floating rates with the following terms:
Debt | Amount | Swap Maturity | Swap Rate (percent) | Fair Value | ||||||||||||
6.95% medium-term notes | $ | 200 | July 14, 2009 | CDOR + 175 bps | $ | 3 |
This contract has been recorded at fair value in other assets. In 2007, the Company recognized a gain of less than $1 million (2006 — $1 million; 2005 — $13 million) on the interest rate swap arrangements.
In 2005 the Company unwound interest rate swaps for proceeds of $37 million. The proceeds have been deferred and are being amortized to income over the remaining term of the underlying debt.
Embedded Derivative
The Company entered into a contract with a Norwegian-based company for drilling services offshore China. The contract currency is U.S. dollars, which is not the functional currency of either transacting party. As a result, this contract has been identified as containing an embedded derivative requiring bifurcation and separate accounting treatment at fair value. This embedded derivative has been recorded at fair value in accounts receivable and other assets and the resulting unrealized gain has been recorded in other expenses in the consolidated statement of earnings for the period. In 2007, the impact was an unrealized gain on the embedded derivative of $101 million.
Foreign Currency Risk Management
The Company manages its exposure to foreign exchange rate fluctuations by balancing the U.S. dollar denominated cash flows with U.S. dollar denominated borrowings and other financial instruments. Husky utilizes spot and forward sales to convert cash flows to or from U.S. or Canadian currency.
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At December 31, 2007, the Company had a cash flow hedge using the following cross currency debt swaps:
Canadian | ||||||||||||||||||||
Debt | Swap Amount | Equivalent | Swap Maturity | Interest Rate | Fair Value | |||||||||||||||
(percent) | ||||||||||||||||||||
6.25% notes | U.S. $ | 150 | $ | 212 | June 15, 2012 | 7.41 | $ | (75 | ) | |||||||||||
6.25% notes | U.S. $ | 75 | $ | 90 | June 15, 2012 | 5.65 | $ | (13 | ) | |||||||||||
6.25% notes | U.S. $ | 50 | $ | 59 | June 15, 2012 | 5.67 | $ | (8 | ) | |||||||||||
6.25% notes | U.S. $ | 75 | $ | 88 | June 15, 2012 | 5.61 | $ | (11 | ) |
These contracts have been recorded at fair value in other long-term liabilities. The portion of the fair value of the derivative related to foreign exchange losses has been recorded in earnings to offset the foreign exchange on the translation of the underlying debt. The remaining loss of $5 million, net of tax of $1 million, has been included in OCI. At December 31, 2007, the balance in accumulated other comprehensive income was $14 million, net of tax of $7 million. In 2007, the Company recognized a loss of $62 million (2006 — $4 million; 2005 — $14 million) on the cross currency debt swaps.
On November 10, 2004, the Company unwound its long-dated forwards, which resulted in a gain of $8 million that was deferred and was recognized into income during 2005 on the dates that the underlying hedged transactions took place.
The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. dollars to Canadian dollars. During 2007, the impact of these contracts was a loss of $18 million (2006 — gain of $2 million; 2005 — gain of $15 million).
The Company entered into forward purchases of U.S. dollars to partially offset the fluctuations in foreign exchange related to the contract for drilling services offshore China, which contains an embedded derivative. At December 31, 2007, the following foreign exchange transactions had been entered into:
Date | Forward Purchases | Canadian Equivalent | Fair Value | |||||||||
October 5, 2007 | U.S. $ | 119 | $ | 117 | $ | 2 | ||||||
October 11, 2007 | U.S. $ | 119 | $ | 116 | $ | 2 | ||||||
October 29, 2007 | U.S. $ | 119 | $ | 115 | $ | 4 |
These forward contracts have been recorded at fair value in accounts receivable and other assets and the resulting gain has been recorded in other expenses in the consolidated statement of earnings. In 2007, the impact was a gain of $8 million.
Effective July 1, 2007, the Company’s U.S. $1.5 billion of debt financing related to the Lima acquisition was designated as a hedge of the Company’s net investment in the U.S. refining and marketing operations, which are considered self-sustaining. The unrealized foreign exchange gain of $102 million, net of tax of $19 million, arising from the translation of the debt is recorded in OCI.
Unrecognized Gains (Losses) on Derivative Instruments
Prior to the adoption of the new Canadian GAAP financial instruments standards, certain gains and losses on derivative instruments were unrecognized. The following table summarizes these unrecognized gains and losses for comparative purposes.
2006 | 2005 | |||||||
Interest rate risk management | ||||||||
Interest rate swaps | $ | 5 | $ | 7 | ||||
Foreign currency risk management | ||||||||
Foreign exchange contracts | (26 | ) | (32 | ) |
Credit Risk
Accounts receivable are predominantly with customers in the energy industry and are subject to normal industry credit risks.
In addition, the Company is exposed to credit related losses in the event of non-performance by counterparties to its derivative financial instruments. The Company’s policy is to primarily deal with major financial institutions and investment grade rated entities to mitigate these risks.
Husky did not have any customers that constituted more than 10% of total sales and operating revenues during 2007.
Note 20
Proposed Transaction with BP
In December 2007, the Company entered into an arrangement to create a 50/50 integrated oil sands joint venture with BP Corporation North America Inc. (“BP”), consisting of upstream and downstream assets. Under the terms of the arrangement, Husky will contribute its Sunrise assets located in the Athabasca oil sands in northeast Alberta to an oil sands partnership and BP will contribute its Toledo refinery located in Ohio, USA to a U.S. joint venture entity. In accordance with Canadian GAAP, these joint entities will be accounted for using the proportionate consolidation method. The transaction is scheduled to close in the first quarter of 2008.
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Document C
Form 40-F
RECONCILIATION TO ACCOUNTING PRINCIPLES GENERALLY ACCEPTED
IN THE UNITED STATES
IN THE UNITED STATES
Table of Contents
Report of Independent Registered Public Accounting Firm on Reconciliation
to Accounting Principles Generally Accepted in the United States
to Accounting Principles Generally Accepted in the United States
To the Board of Directors of Husky Energy Inc.
On February 4, 2008, we reported on the consolidated balance sheets of Husky Energy Inc. (“the Company”) as at December 31, 2007, 2006 and 2005 and the consolidated statements of earnings and comprehensive income, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2007 which are included in the annual report onForm 40-F. In connection with our audits of the aforementioned consolidated financial statements, we also have audited the related supplemental note entitled “Reconciliation to Accounting Principles Generally Accepted in the United States” included in theForm 40-F. This supplemental note is the responsibility of the Company’s management. Our responsibility is to express an opinion on this supplemental note based on our audits.
In our opinion, such supplemental note, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ KPMG llp
KPMGllp
Chartered Accountants
Calgary, Canada
February 4, 2008
February 4, 2008
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Table of Contents
Reconciliation to Accounting Principles Generally Accepted in the United States
The Company’s consolidated financial statements have been prepared in accordance with GAAP in Canada, which differ in some respects from those in the United States. Any differences in accounting principles as they pertain to the accompanying consolidated financial statements were insignificant except as described below:
Consolidated Statements of Earnings
2007 | 2006 | 2005 | ||||||||||
($ millions, except per | ||||||||||||
share amounts) | ||||||||||||
Net earnings under Canadian GAAP | $ | 3,214 | $ | 2,726 | $ | 2,003 | ||||||
Adjustments: | ||||||||||||
Full cost accounting (a) | 56 | 64 | 66 | |||||||||
Related income taxes | (17 | ) | (20 | ) | (23 | ) | ||||||
Energy trading contracts (c) | — | 4 | — | |||||||||
Related income taxes | — | (1 | ) | — | ||||||||
Stock-based compensation (d) | (43 | ) | (10 | ) | — | |||||||
Related income taxes | 13 | 3 | — | |||||||||
Earnings before cumulative effect of change in accounting principle under U.S. GAAP | 3,223 | 2,766 | 2,046 | |||||||||
Cumulative effect of change in accounting principle, net of tax (d) | — | 11 | — | |||||||||
Net earnings under U.S. GAAP | $ | 3,223 | $ | 2,777 | $ | 2,046 | ||||||
Weighted average number of common shares outstanding under U.S. GAAP(millions) | ||||||||||||
Basic and diluted | 848.8 | 848.4 | 847.9 | |||||||||
Earnings per share before cumulative effect of change in accounting principle under U.S. GAAP | ||||||||||||
Basic and diluted | $ | 3.80 | $ | 3.26 | $ | 2.41 | ||||||
Earnings per share under U.S. GAAP | ||||||||||||
Basic and diluted | $ | 3.80 | $ | 3.27 | $ | 2.41 |
Condensed Consolidated Balance Sheets
2007 | 2006 | 2005 | ||||||||||||||||||||||
Canadian | U.S. | Canadian | U.S. | Canadian | U.S. | |||||||||||||||||||
GAAP | GAAP | GAAP | GAAP | GAAP | GAAP | |||||||||||||||||||
($ millions) | ||||||||||||||||||||||||
Current assets (b)(c) | $ | 3,048 | $ | 3,048 | $ | 2,179 | $ | 2,190 | $ | 1,535 | $ | 1,591 | ||||||||||||
Property, plant and equipment, net (a) | 17,805 | 17,431 | 15,550 | 15,120 | 13,959 | 13,465 | ||||||||||||||||||
Other assets (g) | 844 | 838 | 204 | 185 | 222 | 223 | ||||||||||||||||||
$ | 21,697 | $ | 21,317 | $ | 17,933 | $ | 17,495 | $ | 15,716 | $ | 15,279 | |||||||||||||
Current liabilities (b)(c)(d)(g)(h) | $ | 3,099 | $ | 3,125 | $ | 2,674 | $ | 2,696 | $ | 2,584 | $ | 2,685 | ||||||||||||
Long-term debt (b) | 2,073 | 2,093 | 1,511 | 1,557 | 1,612 | 1,670 | ||||||||||||||||||
Other long-term liabilities (b)(d)(g) | 918 | 955 | 756 | 749 | 730 | 688 | ||||||||||||||||||
Future income taxes (a)(b)(c)(d)(g)(h) | 3,957 | 3,806 | 3,372 | 3,210 | 3,270 | 3,089 | ||||||||||||||||||
Share capital (d)(e)(f) | 3,551 | 3,785 | 3,533 | 3,767 | 3,523 | 3,757 | ||||||||||||||||||
Retained earnings | 8,176 | 7,666 | 6,087 | 5,572 | 3,997 | 3,431 | ||||||||||||||||||
Accumulated other comprehensive income | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges, net of tax (b) | (4 | ) | (4 | ) | — | (18 | ) | — | (21 | ) | ||||||||||||||
Cumulative foreign currency translation | (175 | ) | (175 | ) | — | — | — | — | ||||||||||||||||
Hedge of net investment, net of tax | 102 | 102 | — | — | — | — | ||||||||||||||||||
Minimum pension liability, net of tax (g) | — | — | — | — | — | (20 | ) | |||||||||||||||||
Pension accounting (g) | — | — | — | (38 | ) | — | — | |||||||||||||||||
Pension obligation (g) | — | (36 | ) | — | — | — | — | |||||||||||||||||
$ | 21,697 | $ | 21,317 | $ | 17,933 | $ | 17,495 | $ | 15,716 | $ | 15,279 | |||||||||||||
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Condensed Consolidated Statements of Retained Earnings and Accumulated Other Comprehensive Income
2007 | 2006 | 2005 | ||||||||||||||||||||||
Canadian | U.S. | Canadian | U.S. | Canadian | U.S. | |||||||||||||||||||
GAAP | GAAP | GAAP | GAAP | GAAP | GAAP | |||||||||||||||||||
($ millions) | ||||||||||||||||||||||||
Retained earnings, beginning of year | $ | 6,087 | $ | 5,572 | $ | 3,997 | $ | 3,431 | $ | 2,694 | $ | 2,085 | ||||||||||||
Net earnings | 3,214 | 3,223 | 2,726 | 2,777 | 2,003 | 2,046 | ||||||||||||||||||
Adoption of financial instruments (b) | 4 | — | — | — | — | — | ||||||||||||||||||
Dividends on common shares | (1,129 | ) | (1,129 | ) | (636 | ) | (636 | ) | (700 | ) | (700 | ) | ||||||||||||
Retained earnings, end of year | $ | 8,176 | $ | 7,666 | $ | 6,087 | $ | 5,572 | $ | 3,997 | $ | 3,431 | ||||||||||||
Accumulated other comprehensive income, beginning of year | $ | — | $ | (56 | ) | $ | — | $ | (41 | ) | $ | — | $ | (35 | ) | |||||||||
Adoption of financial instruments (b) | (18 | ) | — | — | — | — | — | |||||||||||||||||
Derivatives designated as cash flow hedges, net of tax (b) | 14 | 14 | — | 3 | — | (1 | ) | |||||||||||||||||
Cumulative foreign currency translation | (175 | ) | (175 | ) | — | — | — | — | ||||||||||||||||
Hedge of net investment, net of tax | 102 | 102 | — | — | — | — | ||||||||||||||||||
Minimum pension liability, net of tax (g) | — | — | — | (5 | ) | — | (5 | ) | ||||||||||||||||
Reversal of minimum pension liability, net of tax (g) | — | — | — | 25 | — | — | ||||||||||||||||||
Pension accounting (g) | — | — | — | (38 | ) | — | — | |||||||||||||||||
Pension obligation (g) | — | 2 | — | — | — | — | ||||||||||||||||||
Accumulated other comprehensive income, end of year | $ | (77 | ) | $ | (113 | ) | $ | — | $ | (56 | ) | $ | — | $ | (41 | ) | ||||||||
Condensed Consolidated Statements of Earnings and Comprehensive Income
2007 | 2006 | 2005 | ||||||||||||||||||||||
Canadian | U.S. | Canadian | U.S. | Canadian | U.S. | |||||||||||||||||||
GAAP | GAAP | GAAP | GAAP | GAAP | GAAP | |||||||||||||||||||
($ millions) | ||||||||||||||||||||||||
Sales and operating revenues (b)(c) | $ | 15,518 | $ | 14,072 | $ | 12,664 | $ | 10,790 | $ | 10,245 | $ | 8,445 | ||||||||||||
Costs and expenses (excluding depletion, depreciation and amortization) (b)(c)(d) | 9,408 | 8,005 | 7,422 | 5,554 | 6,112 | 4,312 | ||||||||||||||||||
Accretion expense | 47 | 47 | 45 | 45 | 33 | 33 | ||||||||||||||||||
Depletion, depreciation and amortization (a) | 1,806 | 1,750 | 1,599 | 1,535 | 1,256 | 1,190 | ||||||||||||||||||
Interest — net | 130 | 130 | 92 | 92 | 32 | 32 | ||||||||||||||||||
Earnings before income taxes | 4,127 | 4,140 | 3,506 | 3,564 | 2,812 | 2,878 | ||||||||||||||||||
Income taxes (a)(c)(d) | 913 | 917 | 780 | 798 | 809 | 832 | ||||||||||||||||||
Earnings before cumulative effect of change in accounting principle | 3,214 | 3,223 | 2,726 | 2,766 | 2,003 | 2,046 | ||||||||||||||||||
Cumulative effect of change in accounting principle, net of tax (d) | — | — | — | 11 | — | — | ||||||||||||||||||
Net earnings | 3,214 | 3,223 | 2,726 | 2,777 | 2,003 | 2,046 | ||||||||||||||||||
Other comprehensive income (b)(g) | (59 | ) | (57 | ) | — | 2 | — | 6 | ||||||||||||||||
Comprehensive income | $ | 3,155 | $ | 3,166 | $ | 2,726 | $ | 2,779 | $ | 2,003 | $ | 2,052 | ||||||||||||
The increases or decreases noted above refer to the following differences between U.S. GAAP and Canadian GAAP:
(a) | Under Canadian GAAP the ceiling test is performed by comparing the carrying value of the cost centre based on the sum of the undiscounted cash flows expected from the cost centre’s use and eventual disposition. If the carrying value is unrecoverable the cost centre is written down to its fair value using the expected present value approach of proved plus probable reserves using future prices. Under U.S. GAAP, companies using the full cost method of accounting for oil and gas producing activities perform a ceiling test on each cost centre using discounted estimated future net revenue from proved oil and gas reserves using a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this reconciliation were those in effect at the applicable year-end. At December 31, 2001, the Company recognized a U.S. GAAP ceiling test write down of $334 million after tax. Depletion expense for U.S. GAAP is reduced by $52 million (2006 — $60 million; 2005 — $62 million), before tax of $16 million (2006 — $19 million; 2005 — $21 million). |
Under U.S. GAAP, prices used in the reserve determination were those in effect at the applicable year-end. For Canadian GAAP, forecast prices are used in the reserve determination. The different prices result in a lower reserve base for U.S. GAAP. Additional depletion of $39 million, net of tax of $14 million, was recorded under U.S. GAAP in December 2004. As of the first quarter of 2005 these reserves became economical again. Depletion expense for U.S. GAAP is reduced by $4 million (2006 and 2005 — $4 million), before tax of $1 million (2006 — $1 million; 2005 — $2 million).
(b) | Effective January 1, 2007, the Company adopted the new Canadian GAAP standards relating to financial instruments. These standards have been adopted prospectively. This new guidance substantially harmonizes Canadian GAAP with U.S. GAAP, with the exception of the treatment of debt issue costs. Under the new Canadian GAAP requirements, unamortized debt issue costs are offset against the related long-term debt. Under U.S. GAAP, debt issue costs are deferred in other assets. At December 31, 2007, $20 million was reclassified from long term-debt to other assets for U.S. GAAP purposes. |
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At December 31, 2006, the Company recorded additional assets and liabilities for U.S. GAAP purposes of $5 million (2005 — $7 million) and $31 million (2005 — $39 million), respectively, for the fair values of derivative financial instruments recorded under Statements of Financial Accounting Standards (“FAS”) 133, “Accounting for Derivative Instruments and Hedging Activities.” For the period ended December 31, 2006, the Company did not have any gains or losses (2005 — gain of less than $1 million, net of tax) for U.S. GAAP purposes with respect to derivatives designated as fair value hedges relating to commodity price risk. In addition, the amount included in OCI was decreased by $3 million net of tax (2005 — increased by $1 million), for changes in the fair values of the derivatives designated as hedges of cash flows relating to commodity price risk, foreign exchange risk and the transfer to income of amounts applicable to cash flows occurring in 2006. In 2005 and 2003 the Company unwound interest rate swaps that were fair value hedges of debt for proceeds of $37 million and $44 million, respectively. Prior to the adoption of the new Canadian GAAP standards relating to financial instruments, the proceeds received were recorded to current and long-term liabilities and were deferred over the life of the debt. For U.S. GAAP purposes, the balance in the current and long-term liabilities was reclassified to long-term debt consistent with fair value hedge treatment. Upon adoption of the new Canadian standards, the treatment of these proceeds are the same as U.S. GAAP.
(c) | Prior to the adoption of the new Canadian standards for financial instruments, Canadian GAAP differed from U.S. GAAP with regards to natural gas purchase and sales contracts. Previously under Canadian GAAP, the impact of energy trading contracts was recorded as the contracts settled. Under the new Canadian standards for financial instruments, natural gas purchase and sale contracts related to energy trading activities are recorded at fair value, consistent with Emerging Issues Task Force (“EITF”)02-03, “Issues Involved in Accounting for Derivative Contracts held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” Under U.S. GAAP, at December 31, 2006, the Company recorded additional assets and liabilities of $6 million (2005 — $49 million) and nil (2005 — $48 million), respectively, and included the unrealized gain, net of tax of $3 million (2005 — gain of less than $1 million), in earnings for the year. For U.S. GAAP, unlike Canadian GAAP, these gains and losses continue to be netted against sales and operating revenues. |
(d) | In January 2006, the Company adopted the fair value accounting provisions under FAS 123(R), “Share-Based Payment.” Under FAS 123(R) awards that are classified as liabilities are re-measured based on the award’s fair value at each reporting date until settlement. Under FAS 123 awards classified as liabilities were measured at their intrinsic value. FAS 123(R) was adopted using the modified prospective application method. The related cumulative effect of the change in accounting principle to net earnings at January 1, 2006 was an increase of $16 million, before tax of $5 million. The change resulted in a decrease to current liabilities of $12 million and long-term liabilities of $4 million and an increase to future income tax liability of $5 million. There was no impact on the Company’s cash flow as a result of adoption of FAS 123(R). |
At December 31, 2007, for U.S. GAAP purposes the Company recorded an increase to current liabilities of $17 million (2006 — decrease of $7 million) and an increase to long-term liabilities of $20 million (2006 — $1 million). The Company also recorded a decrease to net earnings of $43 million (2006 — increase of $6 million), before tax of $13 million (2006 — $2 million).
Under FAS 123(R), the Company is using the Black-Scholes option pricing model to estimate the fair value of the liability related to the options issued under the Company’s tandem plan. The assumptions used in calculating fair value were:
2007 | 2006 | |||||||
Initial expected life(years) | 3.5 | 3.5 | ||||||
Expected annual dividend per share | $ | 1.32 | $ | 1.00 | ||||
Range of expected volatilities used(%) | 21.4 - 27.1 | 19.1 - 29.4 | ||||||
Weighted-average expected volatility(%) | 25.5 | 27.6 | ||||||
Range of risk-free interest rates used(%) | 3.7 - 3.9 | 3.9 - 4.2 |
At December 31, 2007, the total intrinsic value of options exercised during the year was $13 million (2006 — $7 million), the share-based liability paid for the year was $151 million (2006 — $97 million) and the total fair value of options vested during the year was $66 million (2006 — $87 million).
The weighted average remaining contractual term of options fully vested and currently exercisable is 1.6 years (2006 — 2.4 years). The aggregate intrinsic value of options fully vested and currently exercisable is $137 million (2006 — $120 million) and the aggregate intrinsic value of options fully vested and expected to vest is $181 million (2006 — $267 million). The unrecognized compensation cost for 2007 related to non-vested awards is $51 million (2006 — $30 million) and the weighted average period that these costs will be recognized over is 1.6 years (2006 — 0.9 years).
(e) | As a result of the reorganization of the capital structure which occurred in 2000, the deficit of Husky Oil Limited of $160 million was eliminated. Elimination of the deficit would not be permitted under U.S. GAAP. |
(f) | Until 1997 the Company recorded interest waived on subordinated shareholders’ loans and dividends waived on Class C shares as a reduction of ownership charges. Under U.S. GAAP, waived interest and dividends in those years would be recorded as interest on subordinated shareholders’ loans and dividends on Class C shares and as capital contributions. |
(g) | In December 2006, the Company adopted FAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Post-retirement Plans.” This standard requires the Company to recognize the overfunded or underfunded status of a defined benefit post-retirement plan as an asset or liability. The funded status is measured as the difference between the fair value of a plan’s assets and its benefit obligations. Changes in this funded status are recognized through comprehensive income in the year in which the change occurs. The additional minimum liability previously recorded under FAS 87 has been eliminated. There is no impact to earnings recognition under the new requirement. |
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The following is the impact of initially applying FAS 158:
Before | After | |||||||||||
FAS 158 | Adoption | FAS 158 | ||||||||||
Adoption | Adjustment | Adoption | ||||||||||
($ millions) | ||||||||||||
Consolidated Balance Sheets | ||||||||||||
Assets | ||||||||||||
Other assets — prepaid pension asset | $ | 19 | $ | (19 | ) | $ | — | |||||
Liabilities and Shareholders’ Equity | ||||||||||||
Additional minimum liability | 36 | (36 | ) | — | ||||||||
Other long-term liabilities — pension payable | 30 | (30 | ) | — | ||||||||
Current liabilities — unfunded status of plan | — | 8 | 8 | |||||||||
Other long-term liabilities — unfunded status of plan | — | 58 | 58 | |||||||||
Future income taxes | 3,216 | (6 | ) | 3,210 | ||||||||
Accumulated other comprehensive income | (43 | ) | (13 | ) | (56 | ) |
At December 31, 2007, the underfunded status of the plan recorded to current and long-term liabilities was $9 million (2006 — $8 million) and $54 million (2006 — $28 million), respectively. OCI was increased by $2 million, net of tax of $1 million.
The amounts reported in accumulated other comprehensive income at December 31, 2007 are comprised of experience gains and losses from prior periods and $3 million (2006 — $5 million) is expected to be recognized as a component of net periodic benefit cost over the next year. The Company does not expect to return any of the plan assets to the Company within the next year.
Under FAS 87, “Employers’ Accounting for Pensions,” the Company amortized the portion of the unrecognized gains or losses that exceeded 10% of the greater of the projected benefit obligation or the market-related value of pension plan assets. The market-related value of pension plan assets is the fair value of the assets or a calculated value that recognizes changes in fair value over not more than five years. An additional minimum liability was recognized if the unfunded accumulated benefit obligation exceeded the unfunded pension cost already recognized. If an additional minimum liability was recognized, an amount equal to the unrecognized prior service cost was recognized as an intangible asset and any excess was reported in OCI. At December 31, 2006, the additional minimum liability was increased by $6 million (2005 — increase of $6 million) with a decrease to OCI of $5 million (2005 — decrease of $5 million), net of tax.
In January 2007, the Company adopted FASB Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes.” This Interpretation clarifies the accounting for the uncertainty in income taxes recognized in accordance with FAS 109. FIN 48 establishes a two-step process for the evaluation of a tax position taken or expected to be taken in a tax return. The first step recognizes whether or not a tax position is sustainable based on a “more-likely-than-not” determination. If the tax position meets the more-likely-than-not threshold, the second step measures the amount of tax benefit to recognize in the financial statements. Under FIN 48, the tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. Husky’s adoption of FIN 48 resulted in no adjustments to its tax provision recorded under Canadian GAAP.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
($ millions) | ||||
Balance at January 1, 2007 | $ | — | ||
Additions based on tax positions related to the current year | 30 | |||
Balance at December 31, 2007 | $ | 30 | ||
The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $30 million.
The Company does not expect any significant changes to its unrecognized tax benefits within the next 12 month period at this time.
The following are the tax years which remain subject to examination by major tax jurisdictions:
Tax Year | Jurisdiction | |
1998 - 2007 | Federal — Canada Revenue Agency (Alberta and Ontario) | |
1999 - 2007 | Internal Revenue Service — United States |
Additional U.S. GAAP Disclosures
Corporate Acquisitions
As described in Note 8 to the Consolidated Financial Statements, effective July 1, 2007, the Company purchased all of the outstanding shares of the Lima Refining Company. This transaction supports the Company’s ongoing strategic plan of expanding its downstream business and further enhances the Company as a fully integrated energy and energy related company.
Accounting for Derivative Instruments and Hedging Activities
Effective January 1, 2001, the Company adopted the provisions of FAS 133, which require that all derivatives be recognized as assets and liabilities on the balance sheet and measured at fair value. Gains or losses, including unrealized amounts, on derivatives that have not been designated as hedges are included in earnings as they arise.
For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with equal or lesser amounts of changes in the fair value of the hedged item. No portion of the fair value of the derivatives related to time value has been excluded from the assessment of hedge effectiveness in these hedging relationships.
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For derivatives designated as cash flow hedges, the portion of the changes in the fair value of the derivatives that are effective in hedging the changes in future cash flows are recognized in OCI until the hedged items are recognized in earnings. Any portion of the change in the fair value of the derivatives that is not effective in hedging the changes in future cash flows is included in earnings. No portion of the fair value of the derivatives related to time value has been excluded from the assessment of hedge effectiveness in these hedging relationships.
Stock Option Plan
In December 2004, the Financial Accounting Standards Board (“FASB”) issued FAS 123(R), which replaced FAS 123 and superseded Accounting Principles Board (“APB”) Opinion 25. FAS 123(R) requires compensation cost related to share-based payments be recognized in the financial statements and that the cost must be measured based on the fair value of the equity or liability instruments issued. Under FAS 123(R) all share-based payment plans must be valued using option-pricing models. For U.S. GAAP, the liability related to the options issued under the Company’s tandem plan is measured at fair value using an option pricing model. Under Canadian GAAP, the liability is measured based on the intrinsic value of the option. Over the life of the option the amount of compensation expense recognized will differ under U.S. and Canadian GAAP, creating a temporary GAAP timing difference. At exercise or surrender of the option, the compensation expense to be recorded will be equal to the cash payment, which will be identical under U.S. and Canadian GAAP and there will no longer be a GAAP difference. FAS 123(R) was effective January 1, 2006.
Depletion, Depreciation and Amortization
Upstream depletion, depreciation and amortization per gross equivalent barrel is calculated by converting natural gas volumes to a barrel of oil equivalent (“boe”) using the ratio of 6 mcf of natural gas to 1 barrel of crude oil (sulphur volumes have been excluded from the calculation). Depletion, depreciation and amortization per boe as calculated under U.S. GAAP for the years ended December 31 were as follows:
2007 | 2006 | 2005 | ||||||||||
Depletion, depreciation and amortization per boe | $ | 11.34 | $ | 10.75 | $ | 9.38 |
Accounting for Certain Hybrid Financial Instruments
In February 2006, the FASB issued FAS 155, “Accounting for Certain Hybrid Financial Instruments — an Amendment of FASB Statements No. 133 and 140,” which addresses a temporary exemption from the application of the bifurcation requirements of FAS 133 to beneficial interests in securitized financial assets. Under the new standard, a requirement exists to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative which requires bifurcation. FAS 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative and would otherwise require bifurcation from the host contract. This standard eliminates the exemption from applying FAS 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. FAS 155 also eliminates the exclusion of a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. FAS 155 was effective for the Company for all financial instruments acquired or issued on or after January 1, 2007. The Company does not have any material hybrid financial instruments.
Accounting for Servicing of Financial Assets
In March 2006, the FASB issued FAS 156, “Accounting for Servicing of Financial Assets — an Amendment of FASB Statement No. 140.” This Statement requires an entity to recognize a servicing asset or servicing liability each time it undergoes an obligation to service a financial asset by entering into certain servicing contracts. All separately recognized servicing assets and servicing liabilities are initially measured at fair value. For subsequent measurement of servicing assets and servicing liabilities, an entity is permitted to choose between the amortization method and the fair value measurement method. FAS 156 requires separate presentation of servicing assets and servicing liabilities subsequently measured in the balance sheet. Additional disclosures are required for separately recognized servicing assets and servicing liabilities. FAS 156 was effective for the Company on January 1, 2007. The application of FAS 156 did not have a material impact on the financial statements.
Accounting for Planned Major Maintenance Activities
In September 2006, the FASB issued FASB Staff Position (FSP) on AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which amends certain provisions in the AICPA Industry Audit Guide, “Audits of Airlines” and APB Opinion No. 28, “Interim Financial Reporting.” This FSP prohibits the use of theaccrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. The guidance in this FSP is applicable to entities in all industries. FSP AUG AIR-1 was effective for the Company on January 1, 2007 and required retrospective application, unless impracticable to do so. The application of FSP AUG AIR-1 did not have an impact on the financial statements.
New Accounting Standards not yet Implemented
Fair Value Measurement
In September 2006, the FASB issued FAS 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in U.S. GAAP pronouncements and expands the disclosure requirements for fair value measurements. Prior to FAS 157, various definitions of fair value existed with limited guidance for application of these definitions in U.S. GAAP. Fair value under this standard is focused on a market-based measurement as opposed to an entity-specific measurement. This standard establishes a fair value hierarchy which distinguishes between market participant assumptions based on market data obtained from independent sources and the reporting entity’s own assumptions about the market. FAS 157 is effective for the Company on January 1, 2008, with the exception of items not recognized or disclosed at fair value in the Company’s financial statements on a recurring basis. FAS 157 is effective for these items on January 1, 2009. The provisions of this Statement are applied prospectively with certain exceptions which require retrospective application. The Company will consider this fair value measurement framework when applying other U.S. GAAP pronouncements where fair value is a consideration.
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Employers’ Accounting for Defined Benefit Pension and Other Post-Retirement Plans
On December 31, 2006, the Company adopted the recognition and disclosure provisions of FAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106 and 132(R).” In addition, FAS 158 has a measurement requirement to measure plan assets and benefit obligations as of the date of the Company’s fiscal year-end balance sheet. This measurement provision is effective for the Company on December 31, 2008. The Company does not expect the application of FAS 158 to have an impact on the financial statements.
Business Combinations and Non-Controlling Interests
In December 2007, the FASB issued FAS 141(R), “Business Combinations (Revised 2007)” and FAS 160, “Non-Controlling Interests in Consolidated Financial Statements — An Amendment of Accounting Research Bulletin (ARB) No. 51.” These standards require the use of fair value accounting for business combinations and non-controlling interests. Equity securities issued as consideration in a business combination will be recorded at fair value as of the acquisition date as opposed to being valued over a period which includes a few days prior to and after the terms of the business combination have been agreed to and announced. In addition, entities will no longer have the ability to capitalize any direct and incremental costs incurred in the business combination. Instead, these transaction costs will require to be expensed under the new standards. The period of one year to complete the accounting for a business combination remains unchanged. Non-controlling interests will require initial measurement at fair value and will be classified as a separate component of equity. FAS 141(R) is to be applied prospectively and is effective for the Company for business combinations for which the acquisition date is on or after January 1, 2009. FAS 160 is effective for the Company on January 1, 2009 and is to be applied prospectively, with the exception of the presentation and disclosure requirements, which will require retrospective application for all periods presented.
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Document D
Form 40-F
Management’s Discussion and Analysis
February 21, 2008
Table of Contents
Husky Energy Inc.
Management’s Discussion and Analysis
For the Year Ended December 31, 2007
February 21, 2008.
Table of Contents
MANAGEMENT’S DISCUSSION AND ANALYSIS
February 21, 2008
TABLE OF CONTENTS
Page | ||||||
1. | Financial Summary | 2 | ||||
1.1 Financial Position | 2 | |||||
1.2 Financial Performance | 2 | |||||
1.3 Selected Annual Information | 3 | |||||
2. | Husky’s Businesses | 3 | ||||
3. | Capability to Deliver Results | 3 | ||||
3.1 Upstream | 3 | |||||
3.2 Midstream | 4 | |||||
3.3 Downstream | 4 | |||||
3.4 Corporate | 4 | |||||
4. | Strategic Plan | 4 | ||||
4.1 Upstream | 4 | |||||
4.2 Midstream | 5 | |||||
4.3 Downstream | 5 | |||||
4.4 Financial Objective | 5 | |||||
5. | Key Performance Drivers | 6 | ||||
5.1 Across Segments | 6 | |||||
5.2 Upstream | 6 | |||||
5.3 Midstream | 7 | |||||
5.4 Downstream | 7 | |||||
5.5 Corporate | 8 | |||||
6. | The 2007 Business Environment | 8 | ||||
6.1 Risk Factors | 8 | |||||
6.2 Commodity Prices and Margins | 9 | |||||
6.3 Sensitivities by Segment for 2007 Results | 11 | |||||
7. | Results of Operations | 12 | ||||
7.1 Segment Earnings | 12 | |||||
7.2 Summary of Quarterly Results | 13 | |||||
7.3 Fourth Quarter | 13 | |||||
7.4 Upstream | 14 | |||||
7.5 Midstream | 23 | |||||
7.6 Downstream | 25 | |||||
7.7 Corporate | 27 | |||||
7.8 Results of Operations for 2006 Compared with 2005 | 28 | |||||
8. | Liquidity and Capital Resources | 28 | ||||
8.1 Summary of Cash Flow | 28 | |||||
8.2 Working Capital Components | 29 | |||||
8.3 Cash Requirements | 31 | |||||
8.4 Off-Balance Sheet Arrangements | 32 | |||||
8.5 Transactions with Related Parties and Major Customers | 32 | |||||
8.6 Financial Risk and Risk Management | 33 | |||||
8.7 Outstanding Share Data | 34 | |||||
9. | Application of Critical Accounting Estimates | 34 | ||||
10. | New and Pending Accounting Standards | 36 | ||||
11. | Reader Advisories | 36 | ||||
11.1 Forward-looking Statements | 36 | |||||
11.2 Oil and Gas Reserve Reporting | 37 | |||||
11.3 Non-GAAP Measures | 38 | |||||
11.4 Additional Reader Advisories | 38 | |||||
11.5 Controls and Procedures | 41 | |||||
12. | Selected Quarterly Financial & Operating Information | 42 |
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1. | FINANCIAL SUMMARY |
1.1 | FINANCIAL POSITION |
1.2 | FINANCIAL PERFORMANCE |
Total Shareholder Returns
The following table shows the total shareholder returns compared with the Standard and Poor’s and the Toronto Stock Exchange energy and composite indices.
Husky common shares | S&P/TSX energy index | S&P/TSX composite index | ||||||||||
2003 | 43% | 24% | 24% | |||||||||
2004 | 46% | 29% | 12% | |||||||||
2005 | 72% | 61% | 22% | |||||||||
2006 | 32% | 3% | 15% | |||||||||
2007 | 14% | 5% | 7% | |||||||||
Five year average | 40% | 23% | 16% | |||||||||
Five year cumulative return | 441% | 178% | 109% |
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1.3 | SELECTED ANNUAL INFORMATION |
2007 | 2006 | 2005 | ||||||||||
($ millions, except where indicated) | ||||||||||||
Sales and operating revenues, net of royalties | $ | 15,518 | $ | 12,664 | $ | 10,245 | ||||||
Segmented earnings | ||||||||||||
Upstream | $ | 2,596 | $ | 2,295 | $ | 1,524 | ||||||
Midstream | 535 | 482 | 495 | |||||||||
Downstream | 297 | 106 | 82 | |||||||||
Corporate and eliminations | (214 | ) | (157 | ) | (98 | ) | ||||||
Net earnings | $ | 3,214 | $ | 2,726 | $ | 2,003 | ||||||
Per share — basic/diluted | $ | 3.79 | $ | 3.21 | $ | 2.36 | ||||||
Dividends per common share | $ | 1.08 | $ | 0.75 | $ | 0.325 | ||||||
Special dividend per common share | $ | 0.25 | $ | — | $ | 0.50 | ||||||
Total assets | $ | 21,697 | $ | 17,933 | $ | 15,716 | ||||||
Long-term debt excluding current portion | $ | 2,073 | $ | 1,511 | $ | 1,612 | ||||||
Return on equity(percent) | 30.2 | 31.8 | 29.2 | |||||||||
Return on average capital employed(percent) | 25.7 | 27.0 | 22.8 |
2. | HUSKY’S BUSINESSES |
Husky is a Canadian-based energy and energy-related company with revenues for the year of $15.5 billion and over 4,000 employees. Husky is integrated through the three industry sectors: upstream, midstream and downstream. In the upstream sector, we explore for, develop and produce crude oil and natural gas (upstream business segment). In the midstream sector, we upgrade heavy crude oil(upgrading business segment), process and pipeline heavy crude oil, maintain interests in two cogeneration plants as well as store and market crude oil and natural gas(infrastructure and marketing business segment). In the downstream sector, we distribute motor fuel and ancillary and convenience products, manufacture and market asphalt products, produce ethanol and operate two regional refineries in Canada(Canadian refined products business segment) and refine crude oil and market refined products in the U.S. Midwest(U.S. refining and marketing business segment).
3. | CAPABILITY TO DELIVER RESULTS |
Husky’s ability to deliver results is dependent on commodity prices, the Company’s continued success in exploring for oil and gas, efficient and safe execution of capital projects, efficient and safe operations, effective marketing, retention of expertise and continued access to the financial markets.
3.1 | UPSTREAM |
• | substantial position in the Alberta oil sands. The initial stages of the development of this asset include the Tucker oil sands project that is currently operating and the Sunrise project that is in the early development phase; | |
• | leading position and extensive expertise in the exploration and production of heavy oil by both cold production and thermal recovery methods in Western Canada; | |
• | large base of producing properties in Western Canada that have responded well to the application of increasingly sophisticated exploitation techniques; | |
• | expertise and experience exploring and developing the significant natural gas potential in the deep basin, foothills, and northwest plains of Alberta and British Columbia; | |
• | harsh weather offshore exploration, development and production expertise as demonstrated by the successful White Rose development offshore the East Coast of Canada. In addition to the White Rose oil field, we hold an interest in Terra Nova and a large portfolio of significant discovery and exploration licenses offshore Newfoundland and Labrador and offshore Greenland; | |
• | large position offshore China that includes an interest in the Wenchang oil field and large portfolio of exploration blocks. By exploration, the Company discovered China’s largest deep water natural gas field in 2006; and | |
• | offshore Indonesia we hold significant discovery and exploration licenses. The Madura natural gas and natural gas liquids discovery is the current focus for development. |
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3.2 | MIDSTREAM |
• | reliable heavy oil upgrading facility located in the Lloydminster heavy oil producing region with a throughput capacity of 82 mbbls/day; | |
• | reliable and efficient heavy oil pipeline systems well integrated in the Lloydminster producing region; | |
• | participation in two cogeneration power facilities having a combined 295 MW of capacity, both of which support local plant operations; | |
• | natural gas storage in excess of 37 bcf, owned and leased; | |
• | large scale petroleum marketer balancing the needs of both customers and suppliers; and | |
• | large scale supplier of crude oil and natural gas feedstock for our plants and facilities. |
3.3 | DOWNSTREAM |
• | 160 mbbls/day full product spectrum refinery at Lima, Ohio, U.S.A.; | |
• | major regional marketer with 505 retail marketing locations including bulk plants and travel centers with strategic land positions in Western Canada; | |
• | refinery in Prince George, British Columbia with 12 mbbls/day capacity of low sulphur gasoline and ultra low sulphur diesel; | |
• | largest producer of ethanol in Western Canada with a combined 260 million litre per year capacity at plants located in Lloydminster, Saskatchewan and Minnedosa, Manitoba; | |
• | largest marketer of paving asphalt in Western Canada with a 28 mbbls/day capacity asphalt refinery located in Lloydminster, integrated with the local heavy oil production transportation and upgrading infrastructure; | |
• | strong product niche in the areas of quality products such as our ethanol enhanced — Mother Nature’s Fuel, Diesel Max, Chevron lubricants and our Black Max polymer modified asphalt; | |
• | full retail network provides for substantial opportunities for ancillary non-fuel income streams, including convenience stores, restaurants, service bays and carwashes; and | |
• | modern retail technology, with a proven new Husky Market design concept. |
3.4 | CORPORATE |
Our corporate capabilities are discussed in the following sections:
• | Section 8. Liquidity and Capital Resources | |
• | Section 11.5 Controls and Procedures |
4. | STRATEGIC PLAN |
Our upstream strategy is to continue exploiting our oil and gas asset base in the Western Canadian Sedimentary Basin while expanding into large scale sustainable areas including the Alberta oil sands, northern basins, Canada’s East Coast, offshore Greenland and highly prospective basins offshore Southeast Asia.
Building on our proven track record of creating value through the integrated production to refined products value chain, we will grow our midstream and downstream throughput capacity to enhance our integration strategy. In the global energy business environment and volatile commodity prices, we must focus on our financial discipline in order to successfully maintain this strategy.
Our current strategic direction by business segments is as follows:
4.1 | UPSTREAM |
• | continue the development of our large holdings in the Alberta oil sands through in-situ recovery methods such as SAGD and other thermal recovery schemes; | |
• | in Western Canada focus on natural gas exploration in the foothills and deep basin, and tight gas and coalbed methane in the plains region. Increase recovery from mature fields through enhanced recovery techniques. Explore in the central Mackenzie region of the Northwest Territories; |
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• | optimize heavy oil production through cold production, thermal recovery techniques and other enhanced recovery techniques; | |
• | maximize the value of the White Rose asset through the development of satellite tieback oil pools. Participate in the continuing development of Terra Nova. Pursue exploration opportunities and evaluate options to develop natural gas discoveries in the region; | |
• | optimize production from the Wenchang oil field offshore China by pursuing infill and optimization opportunities; | |
• | delineate the Liwan discovery offshore China and continue exploration in the surrounding area to complete the evaluation of Block 29/26. Continue exploration of our extensive acreage position offshore China and advance development options for Liwan discovery; | |
• | advance the development of the Madura field offshore Indonesia and continue exploration on the Madura and East Bawean II production sharing contracts; and | |
• | explore offshore Greenland, leveraging the experience we have gained off the East Coast of Canada. |
4.2 | MIDSTREAM |
• | continue to enhance and expand our infrastructure in the Lloydminster area and optimize the integration of the upgrader, pipeline, asphalt refinery, cogeneration and ethanol facilities; | |
• | further expand the Company’s natural gas business; | |
• | enhance and expand our terminalling infrastructure and services to meet the requirements associated with growing bitumen and heavy oil development; | |
• | position the Company with greenhouse gas management strategies including participation in industry initiatives, carbon offset opportunities and identification of carbon credit and trading opportunities; and | |
• | identify and pursue logistics opportunities to meet the requirements associated with the Sunrise development and downstream initiatives. |
4.3 | DOWNSTREAM |
• | look at opportunities to expand asphalt production in Lloydminster; | |
• | optimize synergies by integrating Lloydminster asphalt refinery outputs with that of the upgrader creating new refined products; | |
• | maximize revenues by producing ethanol efficiently and effectively and marketing it profitably; | |
• | construction of strategically located new outlets, enhancement of nonfuel income streams, upgrading of existing petroleum outlets and the sale of nonperforming locations; | |
• | modernize, automate and upgrade existing petroleum outlets and technology used in operations; | |
• | pursue mergers, joint venture or form partnerships in the light oil business outside of Western Canada; | |
• | reconfigure and expand the Lima, Ohio refinery to improve operations and profitability by processing heavier crudes and bitumen blends; and | |
• | reconfigure and expand the Toledo, Ohio refinery to accommodate Sunrise production as its primary feedstock. |
4.4 | FINANCIAL OBJECTIVE |
Our financial objective is to maintain a strong financial position providing us with the ability to undertake large capital growth projects and providing shareholders with a strong regular return on their investment.
Over the business cycle we intend to:
• | maintain debt to capitalization ratio of less than 40%; and | |
• | maintain debt to cash flow from operations of less than two times. |
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5. | KEY PERFORMANCE DRIVERS |
To achieve corporate strategic objectives and provide our shareholders with a good return on investment, we need to capture opportunities that will drive corporate performance and increase our position to capture future opportunities. During 2007, key performance drivers that emerged or were advanced are noted below:
5.1 | ACROSS SEGMENTS |
Integrated Oil Sands Joint Development
On December 5, 2007, Husky announced a joint venture with BP to create an integrated oil sands business. The development consists of a 50/50 partnership to develop the Sunrise oil sands project in the Athabasca oil sands deposit, which Husky will operate and the formation of a 50/50 limited liability company for the existing Toledo, Ohio BP refinery, which BP will operate. These transactions are expected to be completed by the end of March 2008. The development of the Sunrise oil sands project is expected to proceed in three phases. The first phase will result in a productive capacity of 60 mbbls/day of bitumen by 2012 and the second and third phases are targeted to increase the productive capacity to approximately 200 mbbls/day of bitumen by 2015 to 2020. The Toledo refinery is expected to be modified by 2015 to process approximately 120 mbbls/day of bitumen feedstock (diluted as required for transportation purposes) matching the first two phases of the Sunrise oil sands development.
5.2 | UPSTREAM |
White Rose Development and Delineation
The White Rose oil field received approval on April 2, 2007 to increase annual production to 50 mmbbls from 36.5 mmbbls. The maximum daily production is increased to 140 mbbls/day, up from 100 mbbls/day. We completed the seventh production well in July 2007, which increased White Rose productive capacity to approximately 140 mbbls/day. With the completion of the second gas injection well in September 2007, the original development plan for the South Avalon portion of the White Rose oil field is complete.
At year-end, the North Amethyst front-end engineering design was complete, the glory hole to accommodate the subsea facilities was complete, a drilling rig had been secured and procurement of long lead equipment was underway. The development application has been submitted for approval by the Canada — Newfoundland and Labrador Offshore Petroleum Board (“CNLOPB”) and the provincial government. West White Rose delineation results are being analyzed. The South White Rose extension development plan was approved by the federal and provincial governments.
East Coast Exploration
The acquisition of3-D seismic covering 2,500 square kilometres is commencing in 2008.
Tucker Oil Sands Project
Tucker production ramp up has been slower than anticipated largely due to the position of some wells relative to the water saturation zone of the reservoir. While optimization strategies are continuing on the existing well pads, the drilling of eight new well pairs on Pad C is complete and a new D pad with well pairs placed in an optimized position in the reservoir has been planned.
Sunrise Oil Sands Project
The front-end engineering design for the Sunrise project was essentially completed. Discussions with regulatory authorities for the development application and the Sunrise project corporate sanction are expected to be in 2008.
Caribou
The front-end engineering design has been finalized for the 10 mbbls/day demonstration project and additional technical work is ongoing. Discussions with regulatory authorities are expected to continue in 2008.
Saleski
The winter drilling program has been reduced from 12 to 6 wells. We are continuing to work on reservoir characterization and various recovery processes.
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McMullen Oil Sands Acquisition
In December 2007, an agreement was executed to purchase 110,000 contiguous acres of oil sands leases at McMullen, located in the west central Athabasca oil sands deposit, for $105 million. We have a 100% working interest in these oil sands leases. This land lies adjacent to oil sands leases that we currently hold.
Northwest Territories Exploration
Drilling on the Exploration License (“EL”) 423 in the Central Mackenzie Valley is planned for the first half of 2008. EL 423 is located approximately 60 kilometres southeast of the Summit Creek B-44 and the Stewart Creek D-57 discovery wells. The Dahadinni B-20 well and the Keele River L-52 well commenced drilling in February, 2008. We hold a 75% working interest in this play.
China Exploration
The acquisition of seismic over Block 29/26 in the South China Sea, including the Liwan natural gas discovery was completed. Delineation of the Liwan area is expected to commence in the second half of 2008 upon the arrival of the West Hercules deep water drilling rig, which is currently being constructed in South Korea.
Three exploration wells are planned to be drilled in the shallow waters of the South and East China seas. The first well is expected to spud in the first half of 2008 on Block 23/15 in the Beibu Wan Basin of the South China Sea north of Hainan Island. The second well is expected to spud on Block 39/05 southwest of the Wenchang oil field in the South China Sea before the end of 2008.
Indonesia Exploration and Development
In October 2007, we concluded natural gas sales agreements of 100 mmcf/day from our Madura BD field, offshore Indonesia. The contracts have a term of 20 years, which commences with first production anticipated in 2011. The development plan and production sharing licence extension were submitted to BPMIGAS and MIGAS, the Indonesian regulatory authorities, for approval. Front-end engineering design will commence once regulatory approvals have been received. On the East Bawean II block we completed the acquisition of 1,400 square kilometres of3-D seismic data.
Land Acquisition Offshore Greenland
During June 2007, we were awarded two exploration licences, Block 5 and Block 7 that cover a combined 21,067 square kilometres. We have an 87.5% working interest in each block and will be the operator. During October 2007, we were awarded a joint working interest in a third exploration licence, Block 6 that covers 13,213 square kilometres. We have a 43.75% non-operated working interest in this licence.
Our work programs for 2008 have been finalized and consist of the acquisition of 3,000 kilometres of2-D seismic over Block 6 and 7,000 kilometres over blocks 5 and 7. Acquisition of the remainder of the hi-resolution aero-gravity and magnetic survey is expected to be completed in the second quarter of 2008.
5.3 | MIDSTREAM |
Lloydminster Pipeline
The Lloydminster to Hardisty, Alberta pipeline expansion project phase one is complete and operational. With the exception of an 11 kilometre section in and around the City of Lloydminster, phase two is complete and operational.
Lloydminster Upgrader Expansion
The expansion of the Lloydminster upgrader from 82 to 150 mbbls/day has been deferred after a review of our options for processing heavy oil following the acquisition of the Lima refinery. The Lloydminster expansion remains an option for the future.
5.4 | DOWNSTREAM |
Acquisition of the Lima Refinery in Ohio
The acquisition of the Lima refinery was completed on July 3, 2007, for a purchase price of U.S. $1.9 billion plus U.S. $540 million for the cost of feedstock and product inventory. The acquisition was effective July 1, 2007. The Lima refinery has an atmospheric crude oil distillation capacity of 160 mbbls/day. The refinery currently processes a light sweet crude oil feedstock slate and produces gasoline and gasoline blendstocks, diesel, jet fuel, petrochemical feedstocks,
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petroleum coke and other byproducts. The refinery is serviced by both feedstock and product pipelines and production is primarily marketed in the Ohio, Illinois, Indiana and southern Michigan markets.
An engineering evaluation is underway to reconfigure the Lima refinery to increase its capacity to process heavy oil and bitumen blend feedstocks.
The acquisition of a 50% interest in the BP Toledo refinery was announced in December 2007 with an effective date of January 1, 2008. The refinery has the capacity to process 150 mbbls/day of crude oil including 60 mbbls/day of blended heavy sour crude.
Ethanol
In early December 2007, production commenced at the Minnedosa, Manitoba ethanol plant. With a design capacity rate of 130 million litres of ethanol per year, the plant will provide ethanol blending feedstock for the emerging market for ethanol blended gasoline.
5.5 | CORPORATE |
In September, 2007, a public debt offering was completed in the United States that consisted of U.S. $300 million of 6.2% notes due on September 15, 2017 and U.S. $450 million of 6.8% notes due September 15, 2037. These notes rank on par with our other unsecured long-term debt. The net proceeds of the offering were used to repay part of the short-term bridge financing used to acquire the Lima refinery.
6. | THE 2007 BUSINESS ENVIRONMENT |
6.1 | RISK FACTORS |
Results are significantly influenced by the global and domestic business environment. Some risk factors are entirely beyond our influence and others can, to some extent, be strategically managed. Salient risk factors include:
• | crude oil and natural gas prices; | |
• | the price differential between light and heavy crude oil and demand related to various crude oil qualities; | |
• | the price differential between refined products and crude oil (Crack Spread); | |
• | the availability of incremental reserves of oil and gas, whether sourced from exploration, improved recovery or acquisitions; | |
• | the availability of prospective drilling rights; | |
• | the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project development; | |
• | the availability and cost of labour, material and equipment to efficiently, effectively and safely undertake capital projects; | |
• | the costs to operate properties, plants and equipment in an efficient, reliable and safe manner; | |
• | potential actions of governments, regulatory authorities and other stakeholders in the jurisdictions where we have operations; | |
• | prevailing climatic conditions in our operating locations; | |
• | the economic conditions of the markets in which we conduct business; | |
• | regulations to deal with climate change issues; | |
• | changes to government fiscal policies; | |
• | the exchange rate between the Canadian and U.S. dollar; | |
• | changes in workforce demographics; and | |
• | the cost and availability of capital. |
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6.2 | COMMODITY PRICES AND MARGINS |
Average Benchmarks | 2007 | 2006 | 2005 | |||||||||||||
Upstream | ||||||||||||||||
WTI crude oil (U.S. $/bbl) | 72.31 | 66.22 | 56.56 | |||||||||||||
Brent crude oil (U.S. $/bbl) | 72.52 | 65.14 | 54.38 | |||||||||||||
Canadian light crude 0.3% sulphur ($/bbl) | 77.07 | 73.29 | 69.28 | |||||||||||||
Lloyd heavy crude oil @ Lloydminster ($/bbl) | 40.75 | 39.92 | 31.07 | |||||||||||||
NYMEX natural gas (U.S. $/mmbtu) | 6.86 | 7.23 | 8.62 | |||||||||||||
NIT natural gas ($/GJ) | 6.26 | 6.62 | 8.04 | |||||||||||||
Midstream heavy crude oil upgrading | ||||||||||||||||
WTI/Lloyd crude blend differential (U.S. $/bbl) | 23.81 | 22.00 | 21.01 | |||||||||||||
Downstream | ||||||||||||||||
New York Harbor 3:2:1 crack spread (U.S. $/bbl) | 14.15 | 9.80 | 9.50 | |||||||||||||
Cross segment | ||||||||||||||||
U.S./Canadian dollar exchange rate (U.S. $) | 0.931 | 0.882 | 0.826 |
As an integrated producer, profitability is largely determined by realized prices for crude oil and natural gas and refinery processing margins including the effect of change in the U.S./Canadian dollar exchange rate. All of our crude oil production and the majority of our natural gas production receive the prevailing market price. The price for crude oil is determined largely by global factors and is beyond our control. The price for natural gas is determined more by the North America fundamentals since virtually all natural gas production in North America is consumed by North American customers, predominantly in the United States. Weather conditions will also exert a dramatic effect on short-term supply and demand.
The effect of a U.S. $1/bbl increase in the average price of WTI in 2007 would have resulted in an increase in upstream pre-tax cash flow of approximately $92 million and an increase in upstream earnings of $63 million. In contrast, if the Canadian dollar strengthened by U.S. $0.01, the reduction in 2007 cash flow and net earnings would have been approximately $72 million and $52 million, respectively.
In midstream and downstream, the price of crude oil represents the largest cost and the price of natural gas is one of the most significant operating costs. The largest cost factor in the midstream — upgrading business segment is the price of heavy crude oil feedstock, which is processed into light synthetic crude oil. The largest cost factors in the downstream sector are the crude feedstock and processing costs. Our Lima refining operations process a mix of different types of crude oil from various sources but are primarily light sweet crude oil. Our refined products business in Canada relies primarily on the cost of purchasing refined products for resale in our retail distribution network. The refined products are acquired from other Canadian refiners at rack prices or exchanged with production from our Prince George refinery.
Refining margins (Crack Spread) are calculated as the price difference between crude oil feedstock and two or more refined products in different proportions. The New York Harbor 3:2:1 Crack Spread is a benchmark and is calculated as the difference between the price of a barrel of WTI crude oil and the sum of the price of two thirds of a barrel of reformulated gasoline and the price of one third of a barrel of heating oil. Each refinery has a unique crack spread depending on several variables. The mix of different grades of crude oil feedstock and the mix of refined products produced result in different refinery crack spread calculations.
During the last few years, the world supply and demand balance for hydrocarbons has been edging toward higher demand and as a result prices have increased. Global economic growth is expected to continue with China and India leading the way. Higher prices have stimulated international efforts to increase production. Any reduction in global demand could set the stage for price declines.
Heavier grades of crude oil trade at a discount to light crude oil refinery feedstock since they are more costly to process into motor fuels.
The majority of our crude oil and natural gas production is marketed in North America.
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Crude Oil
In 2007, the price of the main benchmark crude oil, West Texas Intermediate (“WTI”), initially declined in the first quarter of 2007, recovered by the end of the first quarter and increased steadily through to the end of July 2007. Except for slight volatility the price of both WTI and Brent increased through the remainder of the third quarter and fourth quarter of 2007, with WTI reaching spot prices just short of U.S. $100/bbl in November. The supply/demand fundamentals supporting crude oil prices did not weaken in 2007. High prices did not result in demand abatement in the United States, the largest crude oil consumer, nor in the high growth emerging economies in Southeast Asia and India. Supply has been affected by OPEC adhering to their production quotas, lower OPEC spare productive capacity, limited refining capacity for heavy crude oil and ongoing geopolitical risk.
Natural Gas
Natural gas inventories were above five year averages and climatic conditions in North America were generally moderate during both the 2007 heating and cooling seasons. These soft market conditions led Husky and other natural gas producers to reallocate capital from natural gas to other areas.
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6.3 | SENSITIVITIES BY SEGMENT FOR 2007 RESULTS |
The following table is indicative of the relative annualized effect on pre-tax cash flow and net earnings from changes in certain key variables in 2007. In essence, the disclosure shows what the effect would have been on 2007 financial results had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during 2007. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.
2007 | Effect on Pre-tax | Effect on | ||||||||||||||||||||||
Sensitivity Analysis | Average | Increase | Cash Flow(6) | Net Earnings(6) | ||||||||||||||||||||
($ millions) | ($/share)(7) | ($ millions) | ($/share)(7) | |||||||||||||||||||||
Upstream and Midstream | ||||||||||||||||||||||||
WTI benchmark crude oil price | $ | 72.31 | U.S. $ | 1.00/bbl | 92 | 0.11 | 63 | 0.07 | ||||||||||||||||
NYMEX benchmark natural gas price(1) | $ | 6.86 | U.S. $ | 0.20/mmbtu | 33 | 0.04 | 23 | 0.03 | ||||||||||||||||
WTI/Lloyd crude blend differential(2) | $ | 23.81 | U.S. $ | 1.00/bbl | (30 | ) | (0.04 | ) | (21 | ) | (0.02 | ) | ||||||||||||
Exchange rate (U.S. $ per Cdn $)(3) | $ | 0.931 | U.S. $ | 0.01 | (72 | ) | (0.08 | ) | (52 | ) | (0.06 | ) | ||||||||||||
Downstream | ||||||||||||||||||||||||
Light oil margins | $ | 0.05 | Cdn $ | 0.005/litre | 16 | 0.02 | 10 | 0.01 | ||||||||||||||||
Asphalt margins | $ | 18.24 | Cdn $ | 1.00/bbl | 8 | 0.01 | 5 | 0.01 | ||||||||||||||||
New York Harbor 3:2:1 crack spread(4) | $ | 14.15 | U.S. $ | 1.00/bbl | 24 | 0.03 | 15 | 0.02 | ||||||||||||||||
Consolidated | ||||||||||||||||||||||||
Year-end translation of U.S. $ debt (U.S. $ per Cdn $) | $ | 1.012 | (5) | U.S.$ | 0.01 | 18 | 0.02 |
(1) | Includes decrease in earnings related to natural gas consumption. |
(2) | Includes impact of upstream and midstream upgrading operations only. |
(3) | Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items. |
(4) | The stated effect has been limited to the 6 month period from July 1, 2007, the effective acquisition date of the Lima refinery. |
(5) | U.S./Canadian dollar exchange rate at December 31, 2007. |
(6) | Excludes derivatives. |
(7) | Based on 849.0 million common shares outstanding as of December 31, 2007. |
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7. | RESULTS OF OPERATIONS |
The earnings of our upstream businesses correlate largely with the prevailing prices for the various grades of crude oil produced and the prices prevailing in the various North American markets for natural gas and natural gas liquids followed by the volume of those commodities that we produce and sell. The earnings of our midstream segment continues the economic value chain through logistics, upgrading, storage, pipeline, processing and marketing. The downstream businesses include refining crude oil into useable products such as transportation fuels, petrochemical feedstocks and road construction materials and marketing them to the end user.
7.1 | SEGMENT EARNINGS |
Midstream | Downstream | |||||||||||||||||||||||||||
Infrastructure | Canadian | U.S. | Corporate | |||||||||||||||||||||||||
and | Refined | Refining and | and | |||||||||||||||||||||||||
Segment Earnings | Upstream | Upgrading | Marketing | Products | Marketing | Eliminations | Total | |||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||
Earnings (loss) before income taxes | $ | 3,299 | $ | 372 | $ | 351 | $ | 242 | $ | 168 | $ | (305 | ) | $ | 4,127 | |||||||||||||
Net earnings (loss) | 2,596 | 282 | 253 | 192 | 105 | (214 | ) | 3,214 | ||||||||||||||||||||
Capital expenditures(1) | 2,388 | 217 | 92 | 212 | 21 | 44 | 2,974 | |||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 2,975 | 382 | 277 | 146 | — | (274 | ) | 3,506 | ||||||||||||||||||||
Net earnings (loss) | 2,295 | 285 | 197 | 106 | — | (157 | ) | 2,726 | ||||||||||||||||||||
Capital expenditures(1) | 2,627 | 184 | 68 | 285 | — | 37 | 3,201 | |||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 2,173 | 449 | 278 | 129 | — | (217 | ) | 2,812 | ||||||||||||||||||||
Net earnings (loss) | 1,524 | 313 | 182 | 82 | — | (98 | ) | 2,003 | ||||||||||||||||||||
Capital expenditures(1) | 2,730 | 120 | 37 | 191 | — | 21 | 3,099 |
(1) | Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions. |
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7.2 | SUMMARY OF QUARTERLY RESULTS |
7.3 | FOURTH QUARTER |
Consolidated net earnings during the fourth quarter of 2007, were $1,074 million, an increase of $532 million or 98% compared with the fourth quarter of 2006. During the fourth quarter of 2007, we recorded a tax benefit of $365 million that resulted from the substantive enactment of Bill C-28 on December 13, 2007. Bill C-28 contains various measures including corporate tax rate reductions. Aside from the non-recurring tax benefit, pre-tax earnings increased by $295 million or 38% in the fourth quarter of 2007 compared with the same period in 2006. Stronger upstream earnings in the fourth quarter of 2007 were due largely to higher crude oil prices, which averaged the highest levels of all eight quarters. Higher pre-tax earnings from the upgrading operations were due to wider average upgrading differentials and higher sales volume. The upgrader operated closer to its capacity during the fourth quarter of 2007 after a second quarter turnaround of 49 days and some additional outages during the third quarter. Downstream pre-tax earnings were higher in the fourth quarter of 2007 because of the 2007 acquisition of the Lima, Ohio refinery. The refinery’s results of operations have been included from the effective date of the acquisition, July 1, 2007.
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7.4 | UPSTREAM |
2007 EARNINGS $2,596 MILLION, UP $301 MILLION FROM 2006
Production
Upstream Results of Operations
Upstream Earnings Summary | 2007 | 2006 | 2005 | |||||||||
($ millions) | ||||||||||||
Gross revenues | $ | 7,287 | $ | 6,586 | $ | 5,207 | ||||||
Royalties | 1,065 | 814 | 840 | |||||||||
Net revenues | 6,222 | 5,772 | 4,367 | |||||||||
Operating and administration expenses | 1,409 | 1,321 | 1,050 | |||||||||
Depletion, depreciation and amortization | 1,615 | 1,476 | 1,144 | |||||||||
Other(1) | (101 | ) | — | — | ||||||||
Income taxes | 703 | 680 | 649 | |||||||||
Earnings | $ | 2,596 | $ | 2,295 | $ | 1,524 | ||||||
(1) | Embedded derivative described below. |
Revenue
Upstream earnings were $301 million higher in 2007 than in 2006 primarily as a result of increased production of light crude oil from the White Rose and Terra Nova oil fields off the East Coast of Canada. Upstream earnings during 2007 were also increased by higher crude oil prices. Upstream earnings were negatively affected by higher royalties on the East Coast production, lower natural gas prices and natural gas production.
Overall crude oil and NGL production increased by 10% in 2007 compared with 2006, White Rose and Terra Nova increased by 45%, Wenchang by 5% partly offset by a 4% decline of crude oil and NGL production from our Western Canada properties. During 2007, White Rose ramped up to a field capacity of 140 mbbls/stream day (102 mbbls/day Husky’s interest) after the completion of the seventh and final production well of the development plan for the South Avalon portion of the White Rose field. Terra Nova returned to full operation in 2007 after a protracted turnaround and major modification of the FPSO in 2006. In Western Canada the ramping up of the Tucker oil sands production lagged as previously described in Section 5. Conventional heavy oil was marginally lower compared with 2006 due to facility issues and some underperforming wells drilled in 2006, partially offset by good results from the well recompletion and optimization program. Conventional light and medium crude oil production was affected by net divestitures and normal production declines.
Natural gas production decreased in 2007 by 7% compared with 2006 primarily as a result of the reallocation of capital spending for natural gas drilling and tie-ins to other portfolio uses in the low natural gas price and higher cost environment. Other contributing factors included land access and well tie-in delays, divestitures of non-core properties and reservoir depletion.
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Operating Costs
Total upstream operating costs averaged $9.09/boe in 2007 compared with $8.77/boe in 2006.
Operating costs in Western Canada conventional averaged $10.93/boe in 2007 compared with $9.79/boe in 2006. Increasing operating costs in Western Canada are related to the nature of exploitation necessary to manage production from maturing fields and new more extensive but less prolific reservoirs. Western Canada operations require increasing amounts of infrastructure including more wells, more extensive pipeline systems, increased water handling and increased use of larger and more extensive natural gas compression systems. In addition, higher levels of industry activity lead to competition for resources and higher service rates and unit costs.
Operating costs at the East Coast offshore operations averaged $4.07/bbl in 2007 compared with $5.48/bbl in 2006. Unit operating costs decreased as a result of lower unit operating costs at White Rose, which benefited by higher production and reliable performance, and Terra Nova which returned to normal production levels following an extended turnaround in 2006.
Operating costs at the South China Sea offshore operations averaged $3.68/bbl compared with $3.61/bbl in 2006.
Depletion, Depreciation and Amortization (“DD&A”)
DD&A under the full cost method of accounting for oil and gas activities is calculated on acountry-by-country basis. The DD&A rate is calculated by dividing the capital costs subject to DD&A by the proved oil and gas reserves expressed as equivalent barrels (“boe”). The resultant dollar per boe is assigned to each boe of production to determine the DD&A expense for the period.
Total DD&A averaged $11.75/boe in 2007 compared with $11.24/boe in 2006.
DD&A in Canada averaged $11.77/boe in 2007 compared with $11.24/boe in 2006. The increase in DD&A results primarily from a higher capital base. The higher capital base is due to added infrastructure in Western Canada and large capital investments required to develop reserves off the East Coast of Canada.
At December 31, 2007, capital costs in respect of unproved properties and major development projects were $2.2 billion compared with $2.1 billion at the end of 2006. These costs are excluded from our DD&A calculation until the unproved properties are evaluated and proved reserves are attributed to the project or the project is deemed to be impaired.
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Embedded Derivative
During 2007, a $101 million gain was recorded on an embedded derivative related to a contract requiring payment in U.S. currency. The payments are expected to occur over the three-year period from mid-2008. This amount will fluctuate with the U.S./Cdn forward exchange rate until the actual contract settlement.
Average Sales Prices | 2007 | 2006 | 2005 | |||||||||
Crude oil ($/bbl) | ||||||||||||
Light crude oil & NGL | $ | 73.54 | $ | 69.06 | $ | 61.56 | ||||||
Medium crude oil | 51.12 | 49.48 | 43.44 | |||||||||
Heavy crude oil & bitumen | 40.19 | 39.92 | 31.09 | |||||||||
Total average | 58.24 | 54.08 | 42.75 | |||||||||
Natural gas ($/mcf) | ||||||||||||
Average | $ | 6.19 | $ | 6.47 | $ | 7.96 |
Upstream Revenue Mix | 2007 | 2006 | 2005 | |||||||||
Percentage of upstream net revenues | ||||||||||||
Crude oil | ||||||||||||
Light crude oil & NGL | 51% | 45% | 29% | |||||||||
Medium crude oil | 7% | 7% | 9% | |||||||||
Heavy crude oil & bitumen | 22% | 24% | 24% | |||||||||
Natural gas | 20% | 24% | 38% | |||||||||
100% | 100% | 100% | ||||||||||
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2007 | 2006 | 2005 | ||||||||||||||||||||||
Netbacks | $ | %(1) | $ | %(1) | $ | %(1) | ||||||||||||||||||
Total | ||||||||||||||||||||||||
Crude oil equivalent(per boe)(2) | ||||||||||||||||||||||||
Gross price | 52.41 | 49.34 | 44.69 | |||||||||||||||||||||
Royalties | 7.74 | 15 | 6.19 | 12 | 7.29 | 17 | ||||||||||||||||||
Net sales price | 44.67 | 43.15 | 37.40 | |||||||||||||||||||||
Operating costs(3) | 9.09 | 17 | 8.77 | 18 | 8.12 | 18 | ||||||||||||||||||
35.58 | 34.38 | 29.28 | ||||||||||||||||||||||
DD&A | 11.75 | 22 | 11.24 | 23 | 9.95 | 22 | ||||||||||||||||||
Administration expenses & other(3) | (0.17 | ) | — | 0.48 | 1 | 0.20 | — | |||||||||||||||||
Earnings before income taxes | 24.00 | 46 | 22.66 | 46 | 19.13 | 43 | ||||||||||||||||||
Canada | ||||||||||||||||||||||||
Crude oil equivalent(per boe)(2) | ||||||||||||||||||||||||
Gross price | 51.54 | 48.48 | 43.69 | |||||||||||||||||||||
Royalties | 7.46 | 14 | 6.00 | 12 | 7.36 | 17 | ||||||||||||||||||
Net sales price | 44.08 | 42.48 | 36.33 | |||||||||||||||||||||
Operating costs(3) | 9.28 | 18 | 9.01 | 19 | 8.39 | 19 | ||||||||||||||||||
Operating netback | 34.80 | 33.47 | 27.94 | |||||||||||||||||||||
Western Canada | ||||||||||||||||||||||||
Crude oil(per boe)(2) | ||||||||||||||||||||||||
Light crude oil | ||||||||||||||||||||||||
Gross price | 61.02 | 59.84 | 60.64 | |||||||||||||||||||||
Royalties | 7.87 | 13 | 7.34 | 12 | 8.66 | 14 | ||||||||||||||||||
Net sales price | 53.15 | 52.50 | 51.98 | |||||||||||||||||||||
Operating costs(3) | 13.24 | 22 | 11.89 | 20 | 9.86 | 16 | ||||||||||||||||||
Operating netback | 39.91 | 40.61 | 42.12 | |||||||||||||||||||||
Medium crude oil | ||||||||||||||||||||||||
Gross price | 50.42 | 48.97 | 43.67 | |||||||||||||||||||||
Royalties | 8.89 | 18 | 8.61 | 18 | 7.77 | 18 | ||||||||||||||||||
Net sales price | 41.53 | 40.36 | 35.90 | |||||||||||||||||||||
Operating costs(3) | 13.92 | 28 | 13.09 | 27 | 10.97 | 25 | ||||||||||||||||||
Operating netback | 27.61 | 27.27 | 24.93 | |||||||||||||||||||||
Heavy crude oil & bitumen | ||||||||||||||||||||||||
Gross price | 40.14 | 39.91 | 31.22 | |||||||||||||||||||||
Royalties | 5.26 | 13 | 5.16 | 13 | 3.75 | 12 | ||||||||||||||||||
Net sales price | 34.88 | 34.75 | 27.47 | |||||||||||||||||||||
Operating costs(3) | 12.81 | 32 | 11.10 | 28 | 9.90 | 32 | ||||||||||||||||||
Operating netback | 22.07 | 23.65 | 17.57 | |||||||||||||||||||||
Natural gas(per mcfge)(4) | ||||||||||||||||||||||||
Gross price | 6.42 | 6.65 | 8.02 | |||||||||||||||||||||
Royalties | 1.23 | 19 | 1.37 | 21 | 1.76 | 22 | ||||||||||||||||||
Net sales price | 5.19 | 5.28 | 6.26 | |||||||||||||||||||||
Operating costs(3) | 1.39 | 22 | 1.18 | 18 | 1.04 | 13 | ||||||||||||||||||
Operating netback | 3.80 | 4.10 | 5.22 | |||||||||||||||||||||
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2007 | 2006 | 2005 | ||||||||||||||||||||||
Netbacks (continued) | $ | %(1) | $ | %(1) | $ | %(1) | ||||||||||||||||||
East Coast | ||||||||||||||||||||||||
Light crude oil(per boe)(2) | ||||||||||||||||||||||||
Gross price | 75.37 | 71.18 | 62.61 | |||||||||||||||||||||
Royalties(5) | 9.43 | 13 | 1.95 | 3 | 5.91 | 9 | ||||||||||||||||||
Net sales price | 65.94 | 69.23 | 56.70 | |||||||||||||||||||||
Operating costs(3) | 4.07 | 5 | 5.48 | 8 | 5.14 | 8 | ||||||||||||||||||
Operating netback | 61.87 | 63.75 | 51.56 | |||||||||||||||||||||
International | ||||||||||||||||||||||||
Light crude oil(per boe)(2) | ||||||||||||||||||||||||
Gross price | 77.07 | 73.60 | 63.15 | |||||||||||||||||||||
Royalties | 15.50 | 20 | 12.17 | 17 | 5.93 | 9 | ||||||||||||||||||
Net sales price | 61.57 | 61.43 | 57.22 | |||||||||||||||||||||
Operating costs(3) | 3.84 | 5 | 3.81 | 5 | 2.92 | 5 | ||||||||||||||||||
Operating netback | 57.73 | 57.62 | 54.30 | |||||||||||||||||||||
(1) | Percent of gross price. |
(2) | Includes associated co-products converted to boe. |
(3) | Operating costs exclude accretion, which is included in administration expenses & other. |
(4) | Includes associated co-products converted to mcfge. |
(5) | During the third quarter of 2007, White Rose royalties increased to 16% because the project, off the East Coast, achieved payout status for Tier 1 royalties. |
Daily Gross Production | 2007 | 2006 | 2005 | |||||||||
Crude oil (mbbls/day) | ||||||||||||
Western Canada | ||||||||||||
Light crude oil & NGL | 26.5 | 30.4 | 31.4 | |||||||||
Medium crude oil | 27.1 | 28.5 | 31.1 | |||||||||
Heavy crude oil & bitumen | 106.9 | 108.1 | 106.0 | |||||||||
160.5 | 167.0 | 168.5 | ||||||||||
East Coast Canada | ||||||||||||
White Rose — light crude oil | 85.0 | 63.8 | 4.8 | |||||||||
Terra Nova — light crude oil | 14.5 | 4.7 | 12.4 | |||||||||
China | ||||||||||||
Wenchang — light crude oil & NGL | 12.7 | 12.1 | 16.0 | |||||||||
272.7 | 247.6 | 201.7 | ||||||||||
Natural gas (mmcf/day) | 623.3 | 672.3 | 680.0 | |||||||||
Total (mboe/day) | 376.6 | 359.7 | 315.0 | |||||||||
2008 Production Guidance
Year ended | Original | |||||||||||
Guidance | December 31 | Guidance | ||||||||||
Gross Production | 2008 | 2007 | 2007 | |||||||||
Crude oil & NGL (mbbls/day) | ||||||||||||
Light crude oil & NGL | 139 - 148 | 139 | 128 - 135 | |||||||||
Medium crude oil | 28 - 29 | 27 | 28 - 30 | |||||||||
Heavy crude oil & bitumen | 114 - 124 | 107 | 122 - 130 | |||||||||
281 - 301 | 273 | 278 - 295 | ||||||||||
Natural gas (mmcf/day) | 625 - 655 | 623 | 670 - 690 | |||||||||
Total barrels of oil equivalent (mboe/day) | 385 - 410 | 377 | 390 - 410 |
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Upstream Capital Expenditure(1) | 2007 | 2006 | 2005 | |||||||||
($ millions) | ||||||||||||
Exploration | ||||||||||||
Western Canada | $ | 456 | $ | 497 | $ | 389 | ||||||
East Coast Canada and Frontier | 84 | 79 | 66 | |||||||||
International | 70 | 77 | 55 | |||||||||
610 | 653 | 510 | ||||||||||
Development | ||||||||||||
Western Canada | 1,575 | 1,675 | 1,618 | |||||||||
East Coast Canada | 197 | 279 | 579 | |||||||||
International | 6 | 20 | 23 | |||||||||
1,778 | 1,974 | 2,220 | ||||||||||
$ | 2,388 | $ | 2,627 | $ | 2,730 | |||||||
(1) | Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions. |
2007 | 2006 | 2005 | ||||||||||||||||||||||
Western Canada Drilling | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
(wells) | ||||||||||||||||||||||||
Exploration | ||||||||||||||||||||||||
Oil | 79 | 79 | 101 | 99 | 89 | 85 | ||||||||||||||||||
Gas | 114 | 92 | 330 | 192 | 392 | 196 | ||||||||||||||||||
Dry | 14 | 12 | 26 | 24 | 36 | 36 | ||||||||||||||||||
207 | 183 | 457 | 315 | 517 | 317 | |||||||||||||||||||
Development | ||||||||||||||||||||||||
Oil | 571 | 530 | 590 | 543 | 466 | 433 | ||||||||||||||||||
Gas | 343 | 251 | 565 | 490 | 610 | 551 | ||||||||||||||||||
Dry | 31 | 29 | 25 | 22 | 42 | 39 | ||||||||||||||||||
945 | 810 | 1,180 | 1,055 | 1,118 | 1,023 | |||||||||||||||||||
Total | 1,152 | 993 | 1,637 | 1,370 | 1,635 | 1,340 | ||||||||||||||||||
Upstream Capital Expenditure — Canada
In 2007, upstream capital spending in Canada amounted to $2,312 million, down from $2,530 million in 2006. Capital spending in 2007 comprised $1,236 million on Western Canada conventional areas ($1,443 million in 2006), $549 million in the Lloydminster heavy oil region ($453 million in 2006), $246 million in the Alberta oil sands regions ($276 million in 2006), $267 million for East Coast development ($313 million in 2006) and $14 million for East Coast and Northwest Territories exploration ($45 million in 2006).
In 2007, spending on exploration activities comprised $158 million in the foothills and deep basin regions of Alberta and north east British Columbia, down $78 million from 2006. Our targets in these regions are predominantly deep natural gas reservoirs that tend to be higher risk but more prolific than elsewhere in the Western Canada Sedimentary Basin. Exploration in this region, which extends along the eastern slopes of the Rocky Mountains in Alberta and into northeastern British Columbia, involves drilling deep wells into higher pressure gas formations. In 2007, the number of natural gas wells drilled was reduced due to low natural gas prices and high costs.
In the Lloydminster heavy oil production region, capital spending was primarily for drilling, well and facility optimization and expansion of thermal operations. The 10 to 14 degree API heavy crude oil is produced by several methods including SAGD, cyclic steam and cold production techniques. Producing technology is constantly being developed and evolving once applied in the field.
Capital spending in the oil sands region was on the Tucker, Sunrise, Caribou and Saleski projects. Our Tucker SAGD oil sands project was commissioned in late 2006. We spent $99 million on the Tucker project in 2007 and expect to spend approximately $100 million in 2008 to increase production. At the Sunrise oil sands project we spent $87 million for
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front-end engineering design, the regulatory approval process and preliminary field work. Sunrise is expected to be developed in three phases as described in Section 5. At Caribou and Saleski approximately $60 million was spent on early stage drilling, facility studies, seismic and technical studies.
At White Rose, production continued to ramp up through 2007 with the drilling of the seventh production well and a second gas injection well. Delineation of several satellite reservoirs to the south, west and north of the South Avalon portion of the field progressed during 2007. Front-end engineering design for the North Amethyst satellite was completed.
Upstream Capital Expenditure — International
Exploration spending totalled $70 million in China and largely involved a seismic program over Block 29/26 covering a total of 3,300 square kilometres. The seismic program was 92% complete prior to being delayed by weather and will be completed in 2008. We also completed the interpretation of seismic data previously acquired over the Liwan natural gas discovery on Block 29/26. In addition, we acquired 1,400 square kilometres of seismic over the East Bawean II Block in the north east Java Basin.
2008 Upstream Capital Program
($ millions) | ||||
Western Canada — oil and gas | $ | 1,670 | ||
— oil sands | 300 | |||
East Coast Canada and Frontier | 650 | |||
International | 430 | |||
$ | 3,050 | |||
Note: Capital program excludes capitalized administration costs, capitalized interest and asset retirement obligations incurred.
Our 2008 capital program concentrates on medium and long-term project development and is 31% above our upstream 2007 capital program spending. Our strategy is to focus on growth and high return projects offshore the East Coast of Canada, China and Indonesia as well as advance the integrated bitumen development at Sunrise.
Given the current low gas price environment, capital expenditure for natural gas development will be allocated to higher return areas, particularly in enhanced oil recovery and in conventional and heavy oil development. Exploration programs in 2008 will include $170 million directed toward opportunities in British Columbia and shallow depth opportunities in Alberta.
We plan to spend $300 million, including $100 million at the Tucker oil sands development, and $160 million on the first phase of the Sunrise project.
Off Canada’s East Coast we plan to spend $425 million on the White Rose satellite tie-back project at North Amethyst and $120 million on the existing White Rose development. In the Central Mackenzie Valley of the Northwest Territories, Husky plans to drill two exploration wells.
Offshore China and Indonesia we plan to spend $430 million in 2008. Approximately $250 million will be spent on drilling, delineation and exploration of the Liwan discovery on Block 29/26 in the South China Sea commencing with delivery of the West Hercules drilling rig in mid-2008. The remainder of the capital program will be used for exploration in the South and East China Seas and development at the Madura BD field, offshore Indonesia. In addition, we plan to spend $40 million on seismic acquisition offshore Greenland.
Oil and Gas Reserves
Husky applied for and was granted an exemption from Canada’s National Instrument51-101 “Standards of Disclosure for Oil and Gas Activities” and provides oil and gas reserves disclosures in accordance with the United States Securities and Exchange Commission (“SEC”) guidelines and the United States Financial Accounting Standards Board (“FASB”) disclosure standards. The information disclosed may differ from information prepared in accordance with National Instrument51-101.
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For more detail on our oil and gas reserves and the disclosures with respect to the FASB’s Statement No. 69, “Disclosures about Oil and Gas Producing Activities” and the differences between our disclosures and those prescribed by National Instrument51-101, refer to our Annual Information Form available atwww.sedar.com or ourForm 40-F available atwww.sec.gov or on our website atwww.huskyenergy.ca.
At December 31, 2007, the present value of future net cash flows after tax from Husky’s proved oil and gas reserves, based on prices and costs in effect at year-end and discounted at 10%, was $14.8 billion compared with $10.1 billion at December 31, 2006.
McDaniel & Associates Consultants Ltd., an independent firm of oil and gas reserves evaluation engineers, was engaged to conduct an audit of Husky’s crude oil, natural gas and natural gas products reserves. McDaniel & Associates Consultants Ltd. issued an audit opinion stating that Husky’s internally generated proved and probable reserves and net present values are, in aggregate, reasonable, and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices in the United States and as set out in the Canadian Oil and Gas Evaluation Handbook.
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Canada | International | Total | ||||||||||||||||||||||||||||||||||||||||||
East | ||||||||||||||||||||||||||||||||||||||||||||
Western Canada | Coast | |||||||||||||||||||||||||||||||||||||||||||
Light | ||||||||||||||||||||||||||||||||||||||||||||
Crude | Medium | Heavy | Light | Crude | ||||||||||||||||||||||||||||||||||||||||
Oil | Crude | Crude | Natural | Crude | Light | Natural | Oil | Natural | Equivalent | |||||||||||||||||||||||||||||||||||
Reconciliation of Proved Reserves | & NGL | Oil | Oil | Bitumen | Gas | Oil | Crude Oil | Gas | & NGL | Gas | Units | |||||||||||||||||||||||||||||||||
(mmbbls) | (mmbbls) | (mmbbls) | (mmbbls) | (bcf) | (mmbbls) | (mmbbls) | (bcf) | (mmbbls) | (bcf) | (mmboe) | ||||||||||||||||||||||||||||||||||
(constant prices and costs before royalties) | ||||||||||||||||||||||||||||||||||||||||||||
Proved reserves at December 31, 2006 | 166 | 87 | 213 | 60 | 2,143 | 107 | 14 | — | 647 | 2,143 | 1,004 | |||||||||||||||||||||||||||||||||
Technical revisions | 1 | 4 | (8 | ) | — | 64 | 26 | 2 | — | 25 | 64 | 36 | ||||||||||||||||||||||||||||||||
Purchase of reserves in place | 1 | — | — | — | 36 | — | — | — | 1 | 36 | 7 | |||||||||||||||||||||||||||||||||
Sale of reserves in place | (10 | ) | — | — | — | (23 | ) | — | — | — | (10 | ) | (23 | ) | (14 | ) | ||||||||||||||||||||||||||||
Discoveries, extensions and improved recovery | 10 | 7 | 38 | 11 | 199 | 19 | — | — | 85 | 199 | 118 | |||||||||||||||||||||||||||||||||
Production | (9 | ) | (10 | ) | (38 | ) | (1 | ) | (228 | ) | (36 | ) | (5 | ) | — | (99 | ) | (228 | ) | (137 | ) | |||||||||||||||||||||||
Proved reserves at December 31, 2007 | 159 | 88 | 205 | 70 | 2,191 | 116 | 11 | — | 649 | 2,191 | 1,014 | |||||||||||||||||||||||||||||||||
Proved and probable reserves At December 31, 2007 | 213 | 105 | 282 | 1,835 | 2,664 | 216 | 37 | 516 | 2,688 | 3,180 | 3,218 | |||||||||||||||||||||||||||||||||
At December 31, 2006 | 219 | 102 | 289 | 1,187 | 2,533 | 186 | 23 | 93 | 2,006 | 2,626 | 2,444 |
Canada | International | Total | ||||||||||||||||||||||||||||||||||||||
East | ||||||||||||||||||||||||||||||||||||||||
Western Canada | Coast | |||||||||||||||||||||||||||||||||||||||
Light | ||||||||||||||||||||||||||||||||||||||||
Crude | Heavy | Light | Crude | |||||||||||||||||||||||||||||||||||||
Oil & | Medium | Crude | Natural | Crude | Light | Oil & | Natural | Equivalent | ||||||||||||||||||||||||||||||||
Reconciliation of Proved Developed Reserves | NGL | Crude Oil | Oil | Bitumen | Gas | Oil | Crude Oil | NGL | Gas | Units | ||||||||||||||||||||||||||||||
(mmbbls) | (mmbbls) | (mmbbls) | (mmbbls) | (bcf) | (mmbbls) | (mmbbls) | (mmbbls) | (bcf) | (mmboe) | |||||||||||||||||||||||||||||||
(constant prices and costs before royalties) | ||||||||||||||||||||||||||||||||||||||||
Proved developed reserves at December 31, 2006 | 147 | 79 | 135 | 47 | 1,703 | 97 | 13 | 518 | 1,703 | 802 | ||||||||||||||||||||||||||||||
Revision of previous estimate | 3 | 9 | 16 | 1 | 180 | 33 | 3 | 65 | 180 | 95 | ||||||||||||||||||||||||||||||
Purchase of reserves in place | — | — | — | — | 30 | — | — | — | 30 | 5 | ||||||||||||||||||||||||||||||
Sale of reserves in place | (9 | ) | — | — | — | (22 | ) | — | — | (9 | ) | (22 | ) | (13 | ) | |||||||||||||||||||||||||
Improved recovery | 4 | 2 | 11 | — | 117 | — | — | 17 | 117 | 36 | ||||||||||||||||||||||||||||||
Production | (9 | ) | (10 | ) | (38 | ) | (1 | ) | (228 | ) | (36 | ) | (5 | ) | (99 | ) | (228 | ) | (137 | ) | ||||||||||||||||||||
Proved developed reserves at December 31, 2007 | 136 | 80 | 124 | 47 | 1,780 | 94 | 11 | 492 | 1,780 | 788 | ||||||||||||||||||||||||||||||
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7.5 | MIDSTREAM |
2007 EARNINGS $535 MILLION, UP $53 MILLION FROM 2006
The midstream business is centered around the upgrading operations, which is a business that adds value to heavy crude oil by converting it to synthetic light crude oil. Unlike heavy crude oil, synthetic crude oil is a higher value feedstock for many refineries in Canada and the United States. During 2007 the price of our synthetic crude oil averaged $79.11/bbl compared with $48.38/bbl, the average price of blended heavy crude oil from the Lloydminster area. This resulted in an average synthetic/heavy crude differential of $30.73/bbl. After the cost of upgrading, which averaged $9.83/bbl, the margin of upgrading Lloydminster heavy crude was $20.90/bbl, up 19% over 2006. Profitability also depends on the level of production or throughput.
Upgrader | Pipelines |
Upgrading Earnings Summary
Upgrader throughput had lower capacity in 2007 due to a 49 day turnaround in the second quarter of 2007 and other minor outages during the year. In September 2007, a debottleneck project was completed that increased throughput capacity to 82 mbbls/stream day. The second phase of an on-stream reliability project is currently underway and is expected to be complete by the second quarter of 2008.
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Upgrading Earnings Summary | 2007 | 2006 | 2005 | |||||||||
($ millions, except | ||||||||||||
where indicated) | ||||||||||||
Gross margin | $ | 614 | $ | 624 | $ | 692 | ||||||
Operating costs | 221 | 224 | 228 | |||||||||
Other recoveries | (4 | ) | (6 | ) | (6 | ) | ||||||
Depreciation and amortization | 25 | 24 | 21 | |||||||||
Income taxes | 90 | 97 | 136 | |||||||||
Earnings | $ | 282 | $ | 285 | $ | 313 | ||||||
Upgrader throughput(1) (mbbls/day) | 61.4 | 71.0 | 66.6 | |||||||||
Synthetic crude oil sales (mbbls/day) | 53.1 | 62.5 | 57.5 | |||||||||
Upgrading differential ($/bbl) | $ | 30.73 | $ | 26.16 | $ | 30.70 | ||||||
Unit margin ($/bbl) | $ | 31.67 | $ | 27.35 | $ | 33.01 | ||||||
Unit operating cost(2) ($/bbl) | $ | 9.83 | $ | 8.65 | $ | 9.38 |
(1) | Throughput includes diluent returned to the field. |
(2) | Based on throughput. |
Infrastructure and Marketing Earnings Summary
Infrastructure and marketing earnings in 2007 increased by $56 million compared with 2006. Higher earnings from oil and gas commodity marketing were realized entirely during the second half of 2007 as crude oil premiums, gas storage profits and NGL extraction margins rose to unprecedented levels. Pipeline earnings in 2007 increased over 2006 supported by higher throughput volume.
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Infrastructure and Marketing Earnings Summary | 2007 | 2006 | 2005 | |||||||||
($ millions, except where indicated) | ||||||||||||
Gross margin | ||||||||||||
Pipeline | $ | 115 | $ | 104 | $ | 92 | ||||||
Other infrastructure and marketing | 278 | 208 | 217 | |||||||||
393 | 312 | 309 | ||||||||||
Other expenses | 14 | 11 | 10 | |||||||||
Depreciation and amortization | 28 | 24 | 21 | |||||||||
Income taxes | 98 | 80 | 96 | |||||||||
Earnings | $ | 253 | $ | 197 | $ | 182 | ||||||
Aggregate pipeline throughput(mbbls/day) | 501 | 475 | 474 |
Midstream Capital Expenditure
Midstream capital expenditure of $309 million in 2007 was primarily for front-end engineering design for the upgrader expansion, debottleneck projects, contingent consideration, equipment and pipeline upgrades and expansion compared with $252 million in 2006.
In midstream, Husky plans to spend $300 million in 2008 of which $75 million will be spent on plant maintenance at the Lloydminster upgrader and $225 million in the pipeline, infrastructure, contingent consideration and other businesses.
7.6 | DOWNSTREAM |
2007 EARNINGS $297 MILLION, UP $191 MILLION FROM 2006
The downstream business is comprised of a Canadian based light oil product (motor fuel) retail and wholesale marketing business, a heavy oil products (asphalt) manufacturing and marketing business and a U.S. based refining and wholesale marketing business. The light oil products business relies primarily on acquiring refined product from other Canadian refiners and to a lesser extent, from our own regional refinery located at Prince George, British Columbia. Asphalt products are sourced from our asphalt plant in Lloydminster, Alberta.
The downstream segment is a margin business, which, in order to provide a return, depends on the unit output prices being sufficiently higher than the unit input costs in order to cover process/operating costs and leave a profit.
In 2007, the downstream segment earnings increased due to the acquisition of the Lima, Ohio refinery, for which results have been included since July 1, 2007, and increased Canadian downstream earnings from higher retail light oil product and asphalt product margins.
Canadian Refined Products
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Downstream Earnings Summaries
Canadian Refined Products Earnings Summary | 2007 | 2006 | 2005 | |||||||||
($ millions, except where indicated) | ||||||||||||
Gross margin | ||||||||||||
Fuel sales | $ | 188 | $ | 138 | $ | 126 | ||||||
Ancillary sales | 42 | 36 | 34 | |||||||||
Asphalt sales | 160 | 94 | 91 | |||||||||
390 | 268 | 251 | ||||||||||
Operating and other expenses | 82 | 74 | 75 | |||||||||
Depreciation and amortization | 66 | 48 | 47 | |||||||||
Income taxes | 50 | 40 | 47 | |||||||||
Earnings | $ | 192 | $ | 106 | $ | 82 | ||||||
Number of fuel outlets | 505 | 505 | 515 | |||||||||
Refined products sales volume | ||||||||||||
Light oil products(million litres/day) | 8.7 | 8.7 | 8.9 | |||||||||
Light oil products per outlet(thousand litres/day) | 13.2 | 12.9 | 12.7 | |||||||||
Asphalt products(mbbls/day) | 21.8 | 23.4 | 22.5 | |||||||||
Refinery throughput | ||||||||||||
Prince George refinery(mbbls/day) | 10.5 | 9.0 | 9.7 | |||||||||
Lloydminster refinery(mbbls/day) | 25.3 | 27.1 | 25.5 | |||||||||
Ethanol production(thousand litres/day) | 324.6 | 59.7 | 25.6 |
U.S. Refining and Marketing Earnings Summary | 2007 | |||
($ millions, except | ||||
where indicated) | ||||
Gross refining margin | $ | 310 | ||
Processing costs | 93 | |||
Operating and other expenses | 1 | |||
Interest — net | 1 | |||
Depreciation and amortization | 47 | |||
Income taxes | 63 | |||
Earnings | $ | 105 | ||
Selected operating data: | ||||
Refinery throughput (mbbls/day) | ||||
Crude oil | 135 | |||
Other feedstock | 9 | |||
Yield (mbbls/day) | ||||
Gasoline | 82 | |||
Middle distillates | 47 | |||
Other fuel and feedstock | 16 | |||
Margins ($/bbl crude throughput) | ||||
Gross refining margin | 12.42 | |||
Unit operating costs ($/bbl of yield) | 3.48 | |||
Refined product sales (mbbls/day) | ||||
Gasoline | 81 | |||
Middle distillates | 46 | |||
Other fuel and feedstock | 13 |
Downstream Capital Expenditure
In 2007, downstream capital expenditure of $233 million was primarily for the construction of the Minnedosa ethanol plant, various capital programs related to environmental protection and reliability upgrades at our refineries and plants and for marketing outlet construction and upgrades. In 2006, total downstream capital expenditures were
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$285 million largely for similar capital programs but also the construction of the Lloydminster ethanol plant, which was commissioned in September 2006.
Downstream plans to spend approximately $300 million in 2008, with $160 million allocated to the Lima refinery for maintenance and for front-end engineering to reconfigure the plant to process heavy oil. The remainder of the capital will be for maintenance of our refining and ethanol assets and remodeling of our retail stations.
7.7 | CORPORATE |
2007 EXPENSE $214 MILLION, UP $57 MILLION FROM 2006
In 2007, intersegment eliminations were $71 million higher than in 2006 as inventory value increased with commodity prices. Corporate expenses decreased in 2007 by $14 million compared with 2006 as a result of several offsetting items. Lower administrative costs were largely due to the result of lower measured stock-based compensation offset partially by higher staffing costs. Interest expense increased due to higher borrowing and lower capitalized interest. In 2007, foreign exchange gains were higher than 2006 due to a further decrease in the Canadian dollar equivalent of our U.S. dollar denominated debt commensurate with the U.S./Canadian dollar exchange rate.
Corporate Earnings Summary | 2007 | 2006 | 2005 | |||||||||
($ millions) income (expense) | ||||||||||||
Intersegment eliminations — net | $ | (51 | ) | $ | 20 | $ | (50 | ) | ||||
Administration expenses | (151 | ) | (199 | ) | (143 | ) | ||||||
Depreciation and amortization | (25 | ) | (27 | ) | (23 | ) | ||||||
Interest — net | (129 | ) | (92 | ) | (32 | ) | ||||||
Foreign exchange | 51 | 24 | 31 | |||||||||
Income taxes | 91 | 117 | 119 | |||||||||
Earnings (expense) | $ | (214 | ) | $ | (157 | ) | $ | (98 | ) | |||
Foreign Exchange Summary | 2007 | 2006 | 2005 | |||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||
(Gain) loss on translation of U.S. dollar denominated long-term debt | ||||||||||||||||||||||||
Realized | $ | — | $ | (42 | ) | $ | (13 | ) | ||||||||||||||||
Unrealized | (197 | ) | 35 | (38 | ) | |||||||||||||||||||
(197 | ) | (7 | ) | (51 | ) | |||||||||||||||||||
Cross currency swaps | ||||||||||||||||||||||||
Realized | — | 47 | — | |||||||||||||||||||||
Unrealized | 62 | (43 | ) | 14 | ||||||||||||||||||||
62 | 4 | 14 | ||||||||||||||||||||||
Other (gains) losses | 84 | (21 | ) | 6 | ||||||||||||||||||||
$ | (51 | ) | $ | (24 | ) | $ | (31 | ) | ||||||||||||||||
U.S./Canadian dollar exchange rates: | ||||||||||||||||||||||||
At beginning of year | U.S. | $ | 0.858 | U.S. | $ | 0.858 | U.S. | $ | 0.831 | |||||||||||||||
At end of year | U.S. | $ | 1.012 | U.S. | $ | 0.858 | U.S. | $ | 0.858 |
Foreign Exchange Risk
Our results are affected by the exchange rate between the Canadian and U.S. dollar. The majority of our revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. The majority of our expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities.
In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in Husky’s U.S. dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2007, 93% or $2.6 billion of our long-term debt was denominated in U.S. dollars. The U.S./Cdn exchange rate at the end of 2007 was U.S. $1.012. The percentage of our long-term debt exposed to the U.S./Cdn exchange rate
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decreases to 80% when the cross currency swaps are included. Additionally, U.S. $1.5 billion of our U.S. dollar denominated debt has been designated as a hedge of a net investment and the unrealized foreign exchange gain is recorded in Other Comprehensive Income, further reducing the long-term debt exposed to the U.S./Cdn exchange rate to 27%. Refer to Section 8.6, “Financial Risk and Risk Management.”
Consolidated Income Taxes
Consolidated income taxes increased in 2007 to $913 million from $780 million in 2006, an effective tax rate of 22% for both 2007 and 2006.
In 2007, a recovery of future income taxes resulted from recording non-recurring tax benefits of $395 million, $365 million due to changes in the tax rate levied by the Federal Government by Bill C-28 and $30 million due to changes from Bill C-52. In 2006, a recovery of future taxes resulted from recording non-recurring tax benefits of $328 million that arose due to changes in the tax rates for the governments of Canada ($198 million), Alberta ($90 million) and Saskatchewan ($40 million).
The following table shows the effect of non-recurring tax benefits for the periods noted:
2007 | 2006 | 2005 | ||||||||||
($ millions) | ||||||||||||
Income taxes before tax amendments | $ | 1,308 | $ | 1,108 | $ | 813 | ||||||
Canadian federal and provincial tax amendments | 395 | 328 | 4 | |||||||||
Income taxes as reported | $ | 913 | $ | 780 | $ | 809 | ||||||
Corporate Capital Expenditure
Corporate capital expenditure of $44 million in 2007 was primarily for computer hardware, software, office furniture and equipment and system upgrades compared with $37 million in 2006.
7.8 | RESULTS OF OPERATIONS FOR 2006 COMPARED WITH 2005 |
Net earnings in 2006 were $2,726 million compared with $2,003 million in 2005. The increase of $723 million was attributable to the following:
Upstream — increase of $771 million due to higher crude oil prices and higher light crude oil production partially offset by lower natural gas sales volume and prices, higher operating costs and DD&A.
Midstream — decrease of $13 million due to narrower upgrading differentials and lower commodity marketing income partially offset by higher crude oil pipeline income.
Downstream — increase of $24 million due to higher margins for motor fuels, higher asphalt product sales volume partially offset by higher depreciation and lower sales volume of motor fuels.
Corporate — expense increased by $59 million due to lower capitalized interest, 2005 litigation settlement, higher staffing costs partially offset by lower intersegment profit eliminations, stock-based compensation and interest expense.
8. | LIQUIDITY AND CAPITAL RESOURCES |
8.1 SUMMARY OF CASH FLOW
2007 | 2006 | 2005 | ||||||||||
Cash flow — operating activities($ millions) | $ | 4,657 | $ | 5,009 | $ | 3,650 | ||||||
— financing activities($ millions) | $ | 433 | $ | (1,626 | ) | $ | (668 | ) | ||||
— investing activities($ millions) | $ | (5,324 | ) | $ | (3,109 | ) | $ | (2,814 | ) | |||
Debt to capital employed(percent) | 19.5 | 14.3 | 20.1 | |||||||||
Corporate reinvestment ratio(1) | 0.9 | 0.7 | 0.8 |
(1) | Reinvestment ratio is based on net capital expenditures including corporate acquisitions. |
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Cash Flow from Operating Activities
In 2007, cash generated by operating activities was $4,657 million, a decrease of $352 million from 2006. The decrease was largely due to an increase in accounts receivable partially offset by higher payables attributable to the U.S. refining and marketing operation acquired in July 2007.
Cash Flow from (used for) Financing Activities
In 2007, cash provided by financing activities amounted to $433 million. The cash provided was largely from the issuance of long-term debt of $7,222 million offset by the repayment of $5,722 million of long-term debt and the payment of dividends of $1,129 million, which resulted in a net amount of $371 million provided. The remaining $62 million of cash provided was from stock option exercises and change in non-cash working capital less debt issue costs.
Cash Flow used for Investing Activities
Cash used in investing activities amounted to $5,324 million in 2007, an increase of $2,215 million over 2006. Cash invested in 2007 was composed of capital expenditures of $2,931 million, corporate acquisition of $2,589 million and $137 million related to change in non-cash working capital and miscellaneous items partially offset by $333 million of proceeds from asset sales.
8.2 | WORKING CAPITAL COMPONENTS |
Working capital is the amount by which current assets exceed current liabilities. At December 31, 2007, our working capital deficiency was $51 million compared with $495 million at December 31, 2006. It is not unusual for us to have working capital deficits at the end of a reporting period. These working capital deficits are primarily the result of accounts payable related to capital expenditures for exploration and development. Settlement of these current liabilities is funded by cash provided by operating activities and to the extent necessary by bank borrowings. This position is a common characteristic of the oil and gas industry which, by the nature of its business, spends large amounts of capital.
2007 | 2006 | Change | ||||||||||||
($ millions) | ||||||||||||||
Current assets | ||||||||||||||
Cash and cash equivalents | $ | 208 | $ | 442 | $ | (234 | ) | Tax payment | ||||||
Accounts receivable | 1,622 | 1,284 | 338 | Inclusion of Lima receivables | ||||||||||
Inventories | 1,190 | 428 | 762 | Inclusion of Lima inventory | ||||||||||
Prepaid expenses | 28 | 25 | 3 | |||||||||||
3,048 | 2,179 | 869 | ||||||||||||
Current liabilities | ||||||||||||||
Accounts payable | 1,460 | 1,268 | (192 | ) | Inclusion of Lima payables offset by lower capital accruals | |||||||||
Accrued interest payable | 20 | 27 | 7 | |||||||||||
Income taxes payable | 36 | 615 | 579 | Tax payment and deferred earnings | ||||||||||
Other accrued liabilities | 842 | 664 | (178 | ) | Higher accruals due to Lima and increase in dividend offset by lower stock-based compensation in 2007 | |||||||||
Long-term debt due within one year | 741 | 100 | (641 | ) | Bridge financing for Lima acquisition | |||||||||
3,099 | 2,674 | (425 | ) | |||||||||||
Working capital | $ | (51 | ) | $ | (495 | ) | $ | 444 | ||||||
Sources and Uses of Cash
Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and develop reserves, to acquire strategic oil and gas assets, repay maturing debt and pay dividends. Husky’s upstream capital programs are funded principally by cash provided from operating activities. During times of low oil and gas prices part of a capital program can generally be deferred. However, due to the long cycle times and the importance to future cash flow in maintaining our production, it may be necessary to utilize alternative sources of capital to continue our strategic investment plan during periods of low commodity prices. As a result, we frequently evaluate our options with respect to
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sources of long and short-term capital resources. In addition, from time to time we engage in hedging a portion of our production to protect cash flow in the event of commodity price declines. Corporate acquisitions, such as the Lima refinery are financed by issuing investment quality funded debt.
As at December 31, 2007, our outstanding long-term debt totalled $2.8 billion, including amounts due within one year, compared with $1.6 billion at December 31, 2006.
During the second quarter of 2007, we arranged short-term bridge financing from several banks to facilitate closing the acquisition of the Lima refinery on July 3, 2007. The bridge financing provided U.S. $1.5 billion while the remaining funds required were drawn under existing credit facilities.
In September 2007, we issued U.S. $300 million of 6.20%10-year notes due September 15, 2017 and U.S. $450 million of 6.80%30-year notes due September 15, 2037 under a shelf prospectus dated September 21, 2006. The net proceeds of these notes were used to repay part of the U.S. $1.5 billion short-term bridge financing for the acquisition of the Lima refinery. Total net proceeds from these issues were U.S. $743 million or $775 million at the then effective exchange rate. The remaining amount that is eligible for issue under our shelf prospectus is U.S. $250 million until October 21, 2008. During the remaining period that the prospectus remains effective, debt securities may be offered in amounts, at prices and on terms to be determined based on market conditions at the time of sale.
At December 31, 2007, we had no drawings under our $1.25 billion revolving syndicated credit facility. Interest rates under this facility vary and are based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected and credit ratings assigned by certain rating agencies to our senior unsecured debt. The syndicated credit facility requires Husky to maintain a debt to cash flow ratio of less than 3.5 times.
At December 31, 2007, we had no draw-down under our $150 million bilateral credit facilities. The terms of these facilities are substantially the same as the syndicated credit facility.
At December 31, 2007, we had utilized $73 million in support of letters of credit under our $270 million in short-term borrowing facilities. The interest rates applicable to these facilities vary and are based on Bankers’ Acceptance, U.S. LIBOR or prime rates. In addition, we utilized $13 million under a $50 million dedicated letter of credit facility.
At a special meeting of the shareholders on June 27, 2007, the shareholders approved atwo-for-one share split of our issued and outstanding common shares. On June 27, 2007, the Company filed Articles of Amendment to effect the share split. All references to common share amounts, including common shares issued and outstanding, basic and diluted earnings per share, dividend per share, weighted average number of common shares outstanding and stock options granted, exercised, surrendered and forfeited have been retroactively restated to reflect the impact of thetwo-for-one share split. The common shares commenced trading on the Toronto Stock Exchange reflecting this split on July 9, 2007.
We declared dividends that aggregated $1.33 per share totalling $1.1 billion in 2007. This included a special dividend of $0.25 per share. The Board of Directors of Husky has established a dividend policy that pays quarterly dividends of $0.33 ($1.32 annually) per common share. The declaration of dividends will be at the discretion of the Board of Directors, which will consider earnings, capital requirements, our financial condition and other relevant factors.
Cash and cash equivalents at December 31, 2007 totalled $208 million compared with $442 million at the beginning of the year.
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December 31, 2007 | ||||||||||||
Outstanding | Available | |||||||||||
Capital Structure | (U.S. $) | (Cdn $) | (Cdn $) | |||||||||
($ millions) | ||||||||||||
Short-term bank debt | $ | — | $ | — | $ | 197 | ||||||
Long-term bank debt | ||||||||||||
Syndicated credit facility | — | — | 1,250 | |||||||||
Bilateral credit facilities | — | — | 150 | |||||||||
Bridge facility | 750 | 741 | ||||||||||
Medium-term notes(1) | — | 200 | ||||||||||
Capital securities | 225 | 223 | ||||||||||
U.S. public notes | 1,650 | 1,630 | ||||||||||
2,625 | 2,794 | 1,597 | ||||||||||
Fair value adjustment(1) | 3 | |||||||||||
Debt issue costs(2) | (20 | ) | ||||||||||
Unwound interest rate swaps(3) | 37 | |||||||||||
Total short-term and long-term debt | $ | 2,625 | $ | 2,814 | $ | 1,597 | ||||||
Common shares, retained earnings and accumulated other comprehensive income | $ | 11,650 | ||||||||||
(1) | The carrying value of the medium-term notes has been adjusted to fair value to meet the accounting requirements for a fair value hedge. Refer to Note 19 to the Consolidated Financial Statements. |
(2) | Debt issue costs have been reclassified to long-term debt with the adoption of financial instruments. Previously these deferred costs were included in other assets. Refer to Note 12 to the Consolidated Financial Statements. |
(3) | The unamortized portion of the gain on previously unwound interest rate swaps that would be designated as fair value hedges is required to be included in the carrying value of long-term debt with the adoption of financial instruments. Refer to Note 12 to the Consolidated Financial Statements. |
Credit Ratings
Husky’s senior debt and capital securities have been rated investment grade by several rating agencies. These ratings are disclosed and explained in detail in our Annual Information Form.
8.3 | CASH REQUIREMENTS |
Contractual Obligations and Other Commercial Commitments
In the normal course of business, Husky is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.
2009- | 2011- | |||||||||||||||||||
Contractual Obligations | Total | 2008 | 2010 | 2012 | Thereafter | |||||||||||||||
Payments due by period ($ millions) | ||||||||||||||||||||
Long-term debt and interest on fixed rate debt | $ | 4,382 | $ | 1,104 | $ | 429 | $ | 595 | $ | 2,254 | ||||||||||
Operating leases | 1,024 | 218 | 553 | 225 | 28 | |||||||||||||||
Firm transportation agreements | 549 | 165 | 168 | 69 | 147 | |||||||||||||||
Unconditional purchase obligations(1) | 4,236 | 2,564 | 1,472 | 161 | 39 | |||||||||||||||
Lease rentals and exploration work agreements | 848 | 175 | 226 | 232 | 215 | |||||||||||||||
Engineering and construction commitments | 71 | 71 | — | — | — | |||||||||||||||
$ | 11,110 | $ | 4,297 | $ | 2,848 | $ | 1,282 | $ | 2,683 | |||||||||||
(1) | Includes purchase of refined petroleum products, processing services, distribution services, insurance premiums and natural gas purchases. |
Based on our 2008 commodity price forecast, we believe that our non-cancellable contractual obligations and other commercial commitments and our 2008 capital program will be funded by cash flow from operating activities and, to the extent required, by available credit facilities. In the event of significantly lower cash flow, we would be able to defer certain of our projected capital expenditures without penalty.
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Estimated Obligations Not Included in the Table
• | Asset retirement obligations (“ARO”) |
Husky currently includes such obligations in the amortizing base of its oil and gas properties. Effective January 1, 2004, with the adoption of the Canadian Institute of Chartered Accountants (“CICA”) section 3110, “Asset Retirement Obligations,” Husky records a separate liability for the fair value of its ARO. See Note 13 to the Consolidated Financial Statements.
• | Employee future benefits |
Husky provides a defined contribution plan and a post-retirement health and dental plan for all qualified employees in Canada. We also provide a defined benefit pension plan for approximately 180 active employees and 480 retirees and their beneficiaries in Canada. This plan was closed to new entrants in 1991 after the majority of our employees transferred to the defined contribution pension plan. We provide a defined benefit pension plan for approximately 385 active employees in the United States. This pension plan was established effective July 1, 2007 in conjunction with the acquisition of the Lima refinery. We also assumed a post-retirement welfare plan covering the employees at the Lima refinery. See Note 17 to the Consolidated Financial Statements.
Other Obligations
Husky is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing and financial impact of these events or rulings prevents any meaningful measurement, which is necessary to assess impact on future liquidity. Such obligations include environmental contingencies, contingent consideration and potential settlements resulting from litigation.
8.4 | OFF-BALANCE SHEET ARRANGEMENTS |
Accounts Receivable Securitization Program
In the ordinary course of business, we engage in the securitization of accounts receivable. The securitization program permits the sale of a maximum of $350 million of accounts receivable on a revolving basis. At December 31, 2007, there were no accounts receivable sold under the program. The securitization agreement terminates on January 31, 2009. The accounts receivable are sold to an unrelated third party and in accordance with the agreement we must provide a loss reserve to replace defaulted receivables.
The securitization program provides us with cost-effective short-term funding for general corporate use. We account for these securitizations as asset sales. In the event the program is terminated our liquidity would not be substantially reduced.
Standby Letters of Credit
In addition, from time to time, we issue letters of credit in connection with transactions in which the counterparty requires such security.
Derivative Instruments
We utilize derivative financial instruments in order to manage unacceptable risk. The derivative financial instruments currently outstanding are listed and discussed in Section 8.6, “Financial Risk and Risk Management.”
8.5 | TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS |
In late 2007, TransAlta Power, L.P. was acquired by an indirect subsidiary of Cheung Kong Infrastructure Holdings Limited, which is majority owned by Hutchison Whampoa Limited, which owns 100% of U.F. Investments (Barbados) Ltd. a 34.58% shareholder in Husky. TransAlta Power L.P. is a 49.99% owner of TransAlta Cogeneration, L.P. our partner in the Meridian Cogeneration plant in Lloydminster, Saskatchewan. We sell natural gas to the Meridian Cogeneration plant and other cogeneration plants owned by TransAlta Power L.P. In 2007, we sold $104 million of natural gas to TransAlta Power L.P.
We did not have any customers that constituted more than 10% of total sales and operating revenues during 2007.
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8.6 | FINANCIAL RISK AND RISK MANAGEMENT |
Husky is exposed to market risks related to the volatility of commodity prices, foreign exchange rates and interest rates. Refer to Section 6 under “The 2007 Business Environment.” From time to time, we use derivative instruments to manage our exposure to these risks.
Commodity Price Risk Management
Husky uses derivative commodity instruments from time to time to manage exposure to price volatility on a portion of its oil and gas production and firm commitments for the purchase or sale of crude oil and natural gas.
Power Consumption
During 2007, we made payments totalling less than $1 million on our power consumption hedges.
Foreign Currency Risk Management
At December 31, 2007, Husky had the following cross currency debt swaps in place:
• | U.S. $150 million at 6.250% swapped at $1.41 to $212 million at 7.41% until June 15, 2012. | |
• | U.S. $75 million at 6.250% swapped at $1.19 to $90 million at 5.65% until June 15, 2012. | |
• | U.S. $50 million at 6.250% swapped at $1.17 to $59 million at 5.67% until June 15, 2012. | |
• | U.S. $75 million at 6.250% swapped at $1.17 to $88 million at 5.61% until June 15, 2012. |
At December 31, 2007 the cost of a U.S. dollar in Canadian currency was $0.9881.
In 2007, the cross currency swaps resulted in an offset to foreign exchange gains on translation of U.S. dollar denominated debt amounting to $62 million.
In addition, we entered into U.S. dollar forward contracts, which resulted in realized losses totalling approximately $18 million in 2007. In 2004, Husky unwound its long-dated forwards resulting in a gain of $8 million, which was recognized into income during 2005 on the dates the underlying hedged transactions took place.
In 2007, we recorded a $101 million gain on an embedded derivative related to a contract requiring payment in U.S. currency. The payments are expected over a three-year period, commencing in 2008. This amount will fluctuate with the U.S./Cdn forward exchange rate until the actual contract settlement.
During the year, the Company entered into forward purchases of U.S. dollars to partially offset the fluctuations in foreign exchange related to the embedded derivative. In 2007, the impact of these transactions was a gain of $8 million.
Effective July 1, 2007, the Company’s U.S. $1.5 billion of debt financing related to the Lima acquisition has been designated as a hedge of the Company’s net investment in the U.S. refining operations, which are considered self-sustaining. The unrealized foreign exchange gain arising from the translation of the debt was $102 million, net of tax of $19 million, which was recorded in “Other Comprehensive Income.”
Interest Rate Risk Management
In 2007, interest rate risk management activities resulted in a decrease to interest expense of less than $1 million.
The cross currency swaps resulted in an addition to interest expense of $6 million in 2007.
We have interest rate swaps on $200 million of long-term debt, effective February 8, 2002, whereby 6.95% was swapped for CDOR + 175 bps until July 14, 2009. During 2007, these swaps resulted in an offset to interest expense amounting to $1 million.
The amortization of previous interest rate swap terminations resulted in an additional $5 million offset to interest expense in 2007.
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8.7 OUTSTANDING SHARE DATA
Authorized:
• | unlimited number of common shares | |
• | unlimited number of preferred shares |
Issued and outstanding: February 15, 2008
• | common shares | 849,018,162 | ||||||
• | preferred shares | none | ||||||
• | stock options | 30,195,824 | ||||||
• | stock options exercisable | 4,021,714 |
At February 15, 2008, 54,563,199 common shares were reserved for issuance under the stock option plan. Options awarded under the stock option plan have a maximum term of five years and vest evenly over the first three years.
9. | APPLICATION OF CRITICAL ACCOUNTING ESTIMATES |
Husky’s Consolidated Financial Statements have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Significant accounting policies are disclosed in Note 3 to the Consolidated Financial Statements. Certain of our accounting policies require subjective judgment about uncertain circumstances. The following discussion highlights the nature and potential effect of these estimates. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.
FULL COST ACCOUNTING FOR OIL AND GAS ACTIVITIES
The indicated change in the following estimates will result in a corresponding increase in the amount of DD&A expense charged to income in a given period:
An increase in:
• | estimated costs to develop the proved undeveloped reserves; | |
• | estimated fair value of the ARO related to the oil and gas properties; and | |
• | estimated impairment of costs excluded from the DD&A calculation. |
A decrease in:
• | previously estimated proved oil and gas reserves; and | |
• | estimated proved reserves added compared to capital invested. |
Depletion Expense
All costs associated with exploration and development are capitalized on acountry-by-country basis. The aggregate of capitalized costs, net of accumulated DD&A, plus the estimated costs required to develop the proved undeveloped reserves, less estimated salvage values, is charged to income over the life of the proved reserves using the unit of production method.
Withheld Costs
Costs related to unproved properties and major development projects are excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. Impairment is transferred to costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.
Ceiling Test
Each cost centre’s capitalized costs are tested for recoverability at least yearly. The test compares the estimated undiscounted future net cash flows from proved oil and gas reserves based on forecast prices and costs to the carrying amount of a cost centre. If the future cash flows are lower than the carrying costs, the cost centre is written down to its fair value. Fair value is estimated using present value techniques, which incorporate risks and other uncertainties as well as the future value of reserves when determining estimated cash flows.
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IMPAIRMENT OF LONG-LIVED ASSETS
Impairment is indicated if the carrying value of the long-lived asset or oil and gas cost centre is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings.
FAIR VALUE OF DERIVATIVE INSTRUMENTS
Periodically we utilize financial derivatives to manage market risk. Effective January 1, 2007, Husky adopted CICA section 3855, “Financial Instruments — Recognition and Measurement,” section 3865, “Hedges,” section 1530, “Comprehensive Income” and section 3861, “Financial Instruments — Disclosure and Presentation.” These standards provide the recognition, measurement and disclosure requirements for financial instruments and hedge accounting. Refer to Note 19 in the Consolidated Financial Statements.
The estimation of the fair value of commodity derivatives incorporates forward prices and adjustments for quality or location. The estimate of fair value for interest rate and foreign currency hedges is determined primarily through forward market prices and compared with quotes from financial institutions. The estimation of fair value for the Company’s embedded derivative and the forward purchases of U.S. dollars to partially offset the fluctuations in foreign exchange related to the embedded derivative is determined using forward market prices.
ASSET RETIREMENT OBLIGATION
We have significant obligations to remove tangible assets and restore land after operations cease and we retire or relinquish the asset. Our ARO primarily relates to the upstream business. The retirement of upstream assets consists primarily of plugging and abandoning wells, removing and disposing of surface andsub-sea equipment and facilities and restoration of land to a state required by regulation or contract. Estimating the ARO requires us to estimate costs that are many years in the future. Restoration technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, future third-party pricing, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Future revisions to these assumptions result in changes to the ARO.
LEGAL, ENVIRONMENTAL REMEDIATION AND OTHER CONTINGENT MATTERS
We are required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined it is charged to earnings. We must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstances.
INCOME TAX ACCOUNTING
The determination of our income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.
BUSINESS COMBINATIONS
Under the purchase method, the acquiring company includes the fair value of the various assets and liabilities of the acquired entity on its balance sheet. The determination of fair value necessarily involves many assumptions. In some circumstances the fair value of an asset is determined by estimating the amount and timing of future cash flow associated with that asset. The actual amounts and timing of cash flow may differ materially and may possibly lead to an impairment charged to earnings.
GOODWILL
In combination with purchase accounting, any excess of the purchase price over fair value is recorded as goodwill. Since goodwill results from the culmination of purchase accounting, described above, it too is inherently imprecise. Goodwill must routinely be assessed for impairment and necessarily requires the judgmental determination of the fair value of assets and liabilities.
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10. | NEW AND PENDING ACCOUNTING STANDARDS |
NEW
Financial Instruments
The new standards for accounting for financial instruments were adopted January 1, 2007. The effect of these standards is disclosed in Note 19 of the Consolidated Financial Statements.
Accounting Changes
In July 2006, the Canadian Accounting Standards Board (“AcSB”) issued a revised CICA section 1506, “Accounting Changes.” Under CICA section 1506, voluntary changes in accounting policy are only permitted if they result in financial statements that provide more reliable and relevant information. Accounting changes are to be applied retrospectively unless impractical. Material prior period errors are applied retrospectively. The revised standard was adopted January 1, 2007 and did not have a material effect on our Consolidated Financial Statements.
PENDING
Financial Instruments — Disclosures and Presentation
In December 2006, the AcSB issued CICA section 3862, “Financial Instruments — Disclosures” and CICA section 3863, “Financial Instruments — Presentation” to replace CICA section 3861, “Financial Instruments — Disclosure and Presentation.” These standards were issued to converge with recently issued International Financial Reporting Standard (“IFRS”) 7. The presentation requirements under section 3863 are unchanged from section 3861. The disclosure requirements under section 3862 have been revised and enhanced. Upon application of section 3862, a reader of our financial statements will be afforded information to evaluate the effect of financial instruments on our financial position and the amount, timing and uncertainty of cash flows associated with financial instruments. Specifically, an increased emphasis has been placed on disclosures regarding the risks associated with recognized and unrecognized financial instruments and how these risks are managed. The disclosures will include both qualitative information about our objectives, policies and processes for risk management and quantitative information that will provide information about the extent to which we are exposed to risk. CICA section 3862 and section 3863 are effective for fiscal years beginning on or after October 1, 2007.
Capital Disclosures
In December 2006, the AcSB issued CICA section 1535, “Capital Disclosures.” This standard was issued to converge with amendments to International Accounting Standard 1. Upon application of these recommendations, readers of financial statements will be provided information pertinent to our objectives, policies and processes for managing capital. We will also disclose quantitative data regarding what we consider capital and whether we are in compliance with all externally imposed capital requirements and the consequences of non-compliance. CICA section 1535 is effective for fiscal years beginning on or after October 1, 2007.
11. | READER ADVISORIES |
11.1 | FORWARD-LOOKING STATEMENTS |
Certain statements in this document are forward-looking statements or information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The Company is hereby providing cautionary statements identifying important factors that could cause the Company’s actual results to differ materially from those projected in these forward-looking statements. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as: “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “intend,” “plan,” “projection,” “could,” “vision,” “goals,” “objective” and “outlook”) are not historical facts and may be forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular, forward-looking statements include: our general strategic plans, our production expectation for the Tucker in-situ oil sands project, the completion of the transactions with BP in respect of the 50/50 partnership to develop the Sunrise oil sands project and the 50/50 limited liability company for the Toledo refinery, our integrated oil sands joint development including the Sunrise oil sands project phased development and Toledo refinery modifications, our conceptual
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development planning for Saleski and Caribou, our White Rose oil field drilling, development and production plans, our East Coast and Northwest Territories exploration programs, our seismic acquisition programs offshore Greenland, the schedule and expected results of our offshore China geophysical and drilling programs, our development plans for the Madura BD field in Indonesia, our plans for expanding our heavy crude oil mainline and the results of the Lima refinery engineering evaluation to increase its heavy oil and bitumen capacity. Accordingly, any such forward-looking statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed throughout this document. Among the key factors that have a direct bearing on our results of operations are the nature of our involvement in the business of exploration for, and development and production of crude oil and natural gas reserves and the fluctuation of the exchange rates between the Canadian and United States dollar.
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include, but are not limited to:
• | adequacy of and fluctuations in oil and natural gas prices; | |
• | demand for our products and services and the cost of required inputs; | |
• | our ability to replace our reserves; | |
• | competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternate sources of energy; | |
• | the occurrence of unexpected events such as fires, blowouts,freeze-ups, equipment failures, natural disasters and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us and that may or may not be financially recoverable; | |
• | actions by governmental authorities, including changes in environmental and other regulations that may impose restrictions in areas where we operate; and | |
• | the accuracy of our oil and gas reserve estimates and estimated production levels as they are affected by our success at exploration and development drilling and related activities and estimated decline rates. |
Further, any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.
11.2 | OIL AND GAS RESERVE REPORTING |
DISCLOSURE OF PROVED OIL AND GAS RESERVES AND OTHER OIL AND GAS INFORMATION
Husky’s disclosure of proved oil and gas reserves and other information about its oil and gas activities has been made based on reliance of an exemption granted by Canadian Securities Administrators. The exemption permits Husky to make these disclosures in accordance with requirements in the United States. These requirements and, consequently, the information presented may differ from Canadian requirements under National Instrument51-101, “Standards of Disclosure for Oil and Gas Activities.” The proved oil and gas reserves disclosed in this document have been evaluated using the United States standards contained inRule 4-10 ofRegulation S-X of the Securities Exchange Act of 1934 and Guide 2 of the Securities Act Industry Guides. The probable oil and gas reserves disclosed in this document have been evaluated in accordance with the Canadian Oil and Gas Evaluation Handbook and National Instrument51-101. Please refer to “Disclosure of Exemption under National Instrument51-101” in the Annual Information Form for the year ended December 31, 2007 filed with securities regulatory authorities for further information.
The Company uses the terms barrels of oil equivalent (“boe”) and thousand cubic feet of gas equivalent (“mcfge”), which are calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the terms boe and mcfge may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent value equivalence at the well head.
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CAUTIONARY NOTE TO U.S. INVESTORS
The United States Securities and Exchange Commission (“SEC”) permits U.S. oil and gas companies, in their filings with the SEC, to disclose only proved reserves, that is reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. We use certain terms in this document such as “probable reserves”, that the SEC’s guidelines strictly prohibit in filings with the SEC by U.S. oil and gas companies. U.S. investors should refer to our Annual Report onForm 40-F available from us or the SEC for further reserve disclosure.
11.3 | NON-GAAP MEASURES |
We use measurements primarily based on GAAP and also on secondary non-GAAP measurements. The non-GAAP measurements included in this report are: Cash flow from operations, Return on equity, Return on capital employed, Debt to capital employed and Corporate reinvestment ratio. None of these measurements is used to enhance our reported financial performance or position. These are useful complementary measurements in assessing our financial performance, efficiency and liquidity. They are common in the reports of other companies but may differ by definition and application. The definitions of these measurements are found in Section 11.4, “Additional Reader Advisories.”
The following table shows the reconciliation of cash flow from operations to cash flow — operating activities for the years ended December 31:
2007 | 2006 | 2005 | ||||||||||
($ millions) | ||||||||||||
Non-GAAP | ||||||||||||
Cash flow from operations | $ | 5,426 | $ | 4,501 | $ | 3,785 | ||||||
Settlement of asset retirement obligations | (51 | ) | (36 | ) | (41 | ) | ||||||
Change in non-cash working capital | (718 | ) | 544 | (72 | ) | |||||||
GAAP | ||||||||||||
Cash flow — operating activities | $ | 4,657 | $ | 5,009 | $ | 3,672 | ||||||
Cash flow from operations is presented in our financial reports because investors use it to analyze operating performance.
11.4 | ADDITIONAL READER ADVISORIES |
Intention of Management’s Discussion and Analysis
This MD&A is intended to provide an explanation of financial and operational performance compared with prior periods and our prospects and plans. It provides additional information that is not contained in our financial statements.
Review by the Audit Committee
This MD&A was reviewed by the Audit Committee and approved by Husky’s Board of Directors on February 21, 2008. Any events subsequent to that date could conceivably materially alter the veracity and usefulness of the information contained in this document.
Additional Husky Documents Filed with Securities Commissions
This MD&A should be read in conjunction with the Consolidated Financial Statements and related Notes. The readers are also encouraged to refer to Husky’s interim reports filed in 2006, which contain MD&A and Consolidated Financial Statements, and Husky’s Annual Information Form filed separately with Canadian regulatory agencies andForm 40-F filed with the SEC, the U.S. regulatory agency. These documents are available atwww.sedar.com, atwww.sec.gov andwww.huskyenergy.ca.
Use of Pronouns and Other Terms
“We”, “our”, “us”, “Husky” and “the Company” refer to Husky Energy Inc. on a consolidated basis.
Standard Comparisons in this Document
Unless otherwise indicated, comparisons of results are for the years ended December 31, 2007 and 2006 and Husky’s financial position as at December 31, 2007 and at December 31, 2006.
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Reclassifications and Materiality for Disclosures
Certain prior year amounts have been reclassified to conform to current year presentation. Materiality for disclosures is determined on the basis of whether the information omitted or misstated would cause a reasonable investor to change their decision to buy, sell or hold the securities of Husky.
Additional Reader Guidance
Unless otherwise indicated:
• | Financial information is presented in accordance with GAAP in Canada. Significant differences between Canadian and United States GAAP are disclosed in the U.S. GAAP reconciliation contained inForm 40-F and available atwww.sedar.com. | |
• | Currency is presented in millions of Canadian dollars (“C$”). | |
• | Gross production and reserves are Husky’s working interest prior to deduction of royalty volume. | |
• | Prices are presented before the effect of hedging. | |
• | Light crude oil is 30o API and above. | |
• | Medium crude oil is 21o API and above but below 30o API. | |
• | Heavy crude oil is above 10o API but below 21o API. | |
• | Bitumen is 10o API and below. |
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ABBREVIATIONS
bbls | barrels | |
bps | basis points | |
mbbls | thousand barrels | |
mbbls/day | thousand barrels per day | |
mmbbls | million barrels | |
mcf | thousand cubic feet | |
mmcf | million cubic feet | |
mmcf/day | million cubic feet per day | |
bcf | billion cubic feet | |
tcf | trillion cubic feet | |
boe | barrels of oil equivalent | |
mboe | thousand barrels of oil equivalent | |
mboe/day | thousand barrels of oil equivalent per day | |
mmboe | million barrels of oil equivalent | |
mcfge | thousand cubic feet of gas equivalent | |
GAAP | Generally Accepted Accounting Principles | |
GJ | gigajoule | |
mmbtu | million British Thermal Units | |
mmlt | million long tons | |
MW | megawatt | |
NGL | natural gas liquids | |
WTI | West Texas Intermediate | |
NYMEX | New York Mercantile Exchange | |
NIT | NOVA Inventory Transfer | |
LIBOR | London Interbank Offered Rate | |
CDOR | Certificate of Deposit Offered Rate | |
SEDAR | System for Electronic Document Analysis and Retrieval | |
FPSO | Floating production, storage and offloading vessel | |
FEED | Front-end engineering design | |
OPEC | Organization of Petroleum Exporting Countries | |
SAGD | Steam-assisted gravity drainage | |
MD&A | Management’s Discussion and Analysis | |
CNLOPB | Canada-Newfoundland and Labrador Offshore Petroleum Board |
TERMS
Bitumen | A naturally occurring viscous mixture consisting mainly of pentanes and heavier hydrocarbons. It is more viscous than 10 degrees API | |
Brent Crude Oil | Prices which are dated less than 15 days prior to loading for delivery | |
Capital Employed | Short- and long-term debt and shareholders’ equity | |
Capital Expenditures | Includes capitalized administrative expenses and capitalized interest but does not include proceeds or other assets | |
Capital Program | Capital expenditures not including capitalized administrative expenses or capitalized interest | |
Cash Flow from Operations | Earnings from operations plus non-cash charges before settlement of asset retirement obligations and change in non-cash working capital | |
Coalbed Methane | Methane (CH4), the principal component of natural gas, is adsorbed in the pores of coal seams | |
Corporate Reinvestment Ratio | Net capital expenditures (capital expenditures net of proceeds from asset sales) plus corporate acquisitions (net assets acquired) divided by cash flow from operations | |
Debt to Capital Employed | Total debt divided by total debt and shareholders’ equity | |
Design Rate Capacity | Maximum continuous rated output of a plant based on its design | |
Embedded Derivative | Implicit or explicit term(s) in a contract that affects some or all of the cash flows or the value of other exchanges required by the contract | |
Feedstock | Raw materials which are processed into petroleum products | |
Front-end Engineering Design | Preliminary engineering and design planning, which among other things, identifies project objectives, scope, alternatives, specifications, risks, costs, schedule and economics | |
Glory Hole | An excavation in the seabed where the wellheads and other equipment are situated to protect them from scouring icebergs | |
Gross/Net Acres/Wells | Gross refers to the total number of acres/wells in which an interest is owned. Net refers to the sum of the fractional working interests owned by a company | |
Gross Reserves/Production | A company’s working interest share of reserves/production before deduction of royalties | |
Interest Coverage Ratio | A calculation of a company’s ability to pay to meet its interest payment obligation. It is equal to earnings before income taxes and interest divided by interest paid before deduction of capitalized interest | |
NOVA Inventory Transfer | Exchange or transfer of title of gas that has been received into the NOVA pipeline system but not yet delivered to a connecting pipeline | |
Polymer | A substance which has a molecular structure built up mainly or entirely of many similar units bonded together | |
Return on Capital Employed | Net earnings plus after tax interest expense divided by average capital employed | |
Return on Shareholders’ Equity | Net earnings divided by average shareholders’ equity | |
Seismic | A method by which the physical attributes in the outer rock shell of the earth are determined by measuring, with a seismograph, the rate of transmission of shock waves through the various rock formations | |
Shareholders’ Equity | Shares, retained earnings and accumulated other comprehensive income | |
Total Debt | Long-term debt including current portion and bank operating loans |
“Proved” reserves have been estimated in accordance with the SEC definition set out inRule 4-10(a) ofRegulation S-X under the Securities Exchange Act of 1934 as follows: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
“Proved Developed” reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved Undeveloped” reserves are those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which a relatively major expenditure is required for recompletion. Inclusion of reserves on undrilled acreage is limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only if it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved and probable reserves.
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11.5 | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
Husky’s management, with the participation of the Chief Executive Officer and in his capacity as Acting Chief Financial Officer, has evaluated the effectiveness of Husky’s disclosure controls and procedures (as defined in the rules of the SEC and the Canadian Securities Administrators (“CSA”)) as at December 31, 2007, and has concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by Husky in reports that it files or submits under the Securities Exchange Act of 1934 is (i) recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and (ii) accumulated and communicated to Husky’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
The following report is provided by management in respect of Husky’s internal controls over financial reporting (as defined in the rules of the SEC and the CSA):
1) | Husky’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Husky. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. | |
2) | Husky’s management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework to evaluate the effectiveness of Husky’s internal control over financial reporting. | |
3) | As at December 31, 2007, management assessed the effectiveness of Husky’s internal control over financial reporting and concluded that such internal control over financial reporting is effective and that there are no material weaknesses in Husky’s internal control over financial reporting that have been identified by management. |
The Company excluded from its assessment the internal control over financial reporting at our Lima refinery, which was acquired effective July 1, 2007. The operations of the Lima refinery are currently being integrated into our operations, including assessing and designing internal controls over financial reporting and disclosure controls and procedures for the Lima refinery operations. At December 31, 2007, total assets of the Lima, Ohio refinery accounted for 14% of the Company’s total consolidated assets and total revenues from the Lima refinery accounted for 15% of the Company’s total consolidated revenues and are included in the December 31, 2007 Consolidated Financial Statements.
4) | KPMG LLP, who has audited the Consolidated Financial Statements of Husky for the year ended December 31, 2007, has also issued a report on internal controls under Auditing Standard No. 5 of the Public Company Accounting Oversight Board (United States). |
Changes in Internal Control over Financial Reporting
There have been no changes in Husky’s internal control over financial reporting during the year ended December 31, 2007, that have materially affected, or are reasonably likely to materially affect its internal control over financial reporting.
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12. | SELECTED QUARTERLY FINANCIAL & OPERATING INFORMATION |
Segmented Operational Information
2007 | 2006 | |||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||
Upstream | ||||||||||||||||||||||||||||||||
Daily production, before royalties | ||||||||||||||||||||||||||||||||
Light crude oil & NGL(mbbls/day) | 129.7 | 133.3 | 144.3 | 147.8 | 128.2 | 117.2 | 97.7 | 100.5 | ||||||||||||||||||||||||
Medium crude oil(mbbls/day) | 27.0 | 26.7 | 26.8 | 27.5 | 28.0 | 28.1 | 28.5 | 29.4 | ||||||||||||||||||||||||
Heavy crude oil & bitumen(mbbls/day) | 107.8 | 106.5 | 105.4 | 108.0 | 109.5 | 107.9 | 105.6 | 109.5 | ||||||||||||||||||||||||
264.5 | 266.5 | 276.5 | 283.3 | 265.7 | 253.2 | 231.8 | 239.4 | |||||||||||||||||||||||||
Natural gas(mmcf/day) | 617.8 | 620.1 | 615.7 | 640.0 | 662.2 | 669.1 | 672.8 | 685.4 | ||||||||||||||||||||||||
Total production(mboe/day) | 367.5 | 369.9 | 379.1 | 390.0 | 376.1 | 364.7 | 344.0 | 353.6 | ||||||||||||||||||||||||
Average sales prices | ||||||||||||||||||||||||||||||||
Light crude oil & NGL($/bbl) | $ | 83.43 | $ | 76.00 | $ | 72.28 | $ | 64.88 | $ | 62.55 | $ | 74.05 | $ | 73.74 | $ | 67.04 | ||||||||||||||||
Medium crude oil($/bbl) | $ | 55.37 | $ | 54.55 | $ | 48.15 | $ | 46.40 | $ | 43.99 | $ | 57.35 | $ | 58.42 | $ | 38.39 | ||||||||||||||||
Heavy crude oil & bitumen($/bbl) | $ | 41.13 | $ | 43.64 | $ | 38.31 | $ | 37.62 | $ | 35.46 | $ | 49.62 | $ | 48.12 | $ | 26.73 | ||||||||||||||||
Natural gas ($/mcf) | $ | 5.72 | $ | 5.18 | $ | 6.91 | $ | 6.94 | $ | 6.19 | $ | 5.69 | $ | 5.95 | $ | 8.06 | ||||||||||||||||
Operating costs ($/boe) | $ | 9.61 | $ | 9.60 | $ | 8.84 | $ | 8.34 | $ | 9.51 | $ | 8.45 | $ | 8.24 | $ | 8.78 | ||||||||||||||||
Operating netbacks(1) | ||||||||||||||||||||||||||||||||
Light crude oil ($/boe)(2) | $ | 61.39 | $ | 53.66 | $ | 59.13 | $ | 56.14 | $ | 51.66 | $ | 61.86 | $ | 60.40 | $ | 54.86 | ||||||||||||||||
Medium crude oil ($/boe)(2) | $ | 29.99 | $ | 28.81 | $ | 26.95 | $ | 24.67 | $ | 21.02 | $ | 33.34 | $ | 35.06 | $ | 19.72 | ||||||||||||||||
Heavy crude oil & bitumen ($/boe)(2) | $ | 21.56 | $ | 25.11 | $ | 20.37 | $ | 21.11 | $ | 18.94 | $ | 32.01 | $ | 31.30 | $ | 12.65 | ||||||||||||||||
Natural gas ($/mcfge)(3) | $ | 3.60 | $ | 3.05 | $ | 4.32 | $ | 4.24 | $ | 3.73 | $ | 3.55 | $ | 3.98 | $ | 5.16 | ||||||||||||||||
Total ($/boe)(2) | $ | 36.01 | $ | 33.68 | $ | 36.91 | $ | 35.70 | $ | 31.00 | $ | 38.46 | $ | 37.34 | $ | 30.89 | ||||||||||||||||
Net wells drilled(4) | ||||||||||||||||||||||||||||||||
Exploration Oil | 23 | 23 | 13 | 20 | 29 | 41 | 7 | 22 | ||||||||||||||||||||||||
Gas | 20 | 13 | 3 | 56 | 42 | 46 | 18 | 86 | ||||||||||||||||||||||||
Dry | — | 2 | 1 | 9 | 2 | 5 | 3 | 14 | ||||||||||||||||||||||||
43 | 38 | 17 | 85 | 73 | 92 | 28 | 122 | |||||||||||||||||||||||||
Development Oil | 143 | 203 | 54 | 130 | 209 | 174 | 57 | 103 | ||||||||||||||||||||||||
Gas | 56 | 54 | 4 | 137 | 159 | 115 | 23 | 193 | ||||||||||||||||||||||||
Dry | 10 | 7 | 2 | 10 | 5 | 6 | 2 | 9 | ||||||||||||||||||||||||
209 | 264 | 60 | 277 | 373 | 295 | 82 | 305 | |||||||||||||||||||||||||
252 | 302 | 77 | 362 | 446 | 387 | 110 | 427 | |||||||||||||||||||||||||
Success ratio(percent) | 96 | 97 | 96 | 95 | 98 | 97 | 95 | 95 | ||||||||||||||||||||||||
Midstream | ||||||||||||||||||||||||||||||||
Synthetic crude oil sales(mbbls/day) | 66.5 | 55.1 | 32.9 | 57.8 | 64.1 | 65.7 | 56.9 | 63.4 | ||||||||||||||||||||||||
Upgrading differential($/bbl) | $ | 36.74 | $ | 30.41 | $ | 30.41 | $ | 24.11 | $ | 23.81 | $ | 23.75 | $ | 22.73 | $ | 34.82 | ||||||||||||||||
Pipeline throughput(mbbls/day) | 497 | 506 | 506 | 493 | 465 | 457 | 480 | 500 | ||||||||||||||||||||||||
Canadian Refined Products | ||||||||||||||||||||||||||||||||
Refined products sales volumes | ||||||||||||||||||||||||||||||||
Light oil products(million litres/day) | 8.5 | 9.0 | 8.6 | 8.9 | 8.6 | 9.1 | 8.6 | 8.6 | ||||||||||||||||||||||||
Asphalt products(mbbls/day) | 24.5 | 25.9 | 19.5 | 17.3 | 21.0 | 30.0 | 24.9 | 17.7 | ||||||||||||||||||||||||
Refinery throughput | ||||||||||||||||||||||||||||||||
Lloydminster refinery(mbbls/day) | 28.8 | 29.0 | 18.5 | 24.7 | 28.1 | 27.9 | 25.4 | 27.1 | ||||||||||||||||||||||||
Prince George refinery(mbbls/day) | 11.6 | 10.8 | 8.4 | 11.1 | 11.2 | 11.6 | 3.7 | 9.3 | ||||||||||||||||||||||||
Refinery utilization(percent) | 101 | 100 | 67 | 90 | 98 | 99 | 73 | 91 |
(1) | Operating netbacks are Husky’s average prices less royalties and operating costs on a per unit basis. |
(2) | Includes associated co-products converted to boe. |
(3) | Includes associated co-products converted to mcfge. |
(4) | Western Canada. |
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Segmented Financial Information
Midstream | ||||||||||||||||||||||||||||||||||||||||||||||||
Upstream | Upgrading | Infrastructure and Marketing | ||||||||||||||||||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 1,568 | $ | 1,496 | $ | 1,593 | $ | 1,565 | $ | 530 | $ | 406 | $ | 229 | $ | 359 | $ | 2,617 | $ | 2,524 | $ | 2,521 | $ | 2,555 | ||||||||||||||||||||||||
Costs and expenses | ||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 358 | 332 | 295 | 323 | 358 | 305 | 186 | 278 | 2,509 | 2,423 | 2,445 | 2,461 | ||||||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 396 | 413 | 407 | 399 | 8 | 7 | 4 | 6 | 7 | 7 | 7 | 7 | ||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
754 | 745 | 702 | 722 | 366 | 312 | 190 | 284 | 2,516 | 2,430 | 2,452 | 2,468 | |||||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 814 | 751 | 891 | 843 | 164 | 94 | 39 | 75 | 101 | 94 | 69 | 87 | ||||||||||||||||||||||||||||||||||||
Current income taxes | 41 | 56 | 3 | 22 | 5 | 4 | — | 1 | 18 | 5 | 29 | 16 | ||||||||||||||||||||||||||||||||||||
Future income taxes | (91 | ) | 179 | 252 | 241 | 22 | 25 | 10 | 23 | 2 | 25 | (8 | ) | 11 | ||||||||||||||||||||||||||||||||||
Net earnings (loss) | $ | 864 | $ | 516 | $ | 636 | $ | 580 | $ | 137 | $ | 65 | $ | 29 | $ | 51 | $ | 81 | $ | 64 | $ | 48 | $ | 60 | ||||||||||||||||||||||||
Capital expenditures(2) | $ | 706 | $ | 545 | $ | 520 | $ | 617 | $ | 44 | $ | 51 | $ | 74 | $ | 48 | $ | 15 | $ | 36 | $ | 5 | $ | 36 | ||||||||||||||||||||||||
Goodwill additions | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||
Total assets | $ | 14,395 | $ | 14,085 | $ | 13,974 | $ | 14,168 | $ | 1,405 | $ | 1,354 | $ | 1,193 | $ | 1,177 | $ | 1,134 | $ | 1,016 | $ | 1,147 | $ | 1,057 | ||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 1,434 | $ | 1,600 | $ | 1,451 | $ | 1,287 | $ | 385 | $ | 485 | $ | 404 | $ | 405 | $ | 2,377 | $ | 2,451 | $ | 2,267 | $ | 2,464 | ||||||||||||||||||||||||
Costs and expenses | ||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 373 | 329 | 308 | 311 | 293 | 399 | 319 | 262 | 2,300 | 2,396 | 2,190 | 2,372 | ||||||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 389 | 382 | 354 | 351 | 6 | 6 | 6 | 6 | 7 | 6 | 5 | 6 | ||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
762 | 711 | 662 | 662 | 299 | 405 | 325 | 268 | 2,307 | 2,402 | 2,195 | 2,378 | |||||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 672 | 889 | 789 | 625 | 86 | 80 | 79 | 137 | 70 | 49 | 72 | 86 | ||||||||||||||||||||||||||||||||||||
Current income taxes | 62 | 158 | 156 | 143 | (31 | ) | 31 | 29 | 24 | 22 | 18 | 20 | 19 | |||||||||||||||||||||||||||||||||||
Future income taxes | 157 | 123 | (189 | ) | 70 | 58 | (5 | ) | (29 | ) | 20 | 2 | (2 | ) | (9 | ) | 10 | |||||||||||||||||||||||||||||||
Net earnings (loss) | $ | 453 | $ | 608 | $ | 822 | $ | 412 | $ | 59 | $ | 54 | $ | 79 | $ | 93 | $ | 46 | $ | 33 | $ | 61 | $ | 57 | ||||||||||||||||||||||||
Capital expenditures(2) | $ | 704 | $ | 612 | $ | 554 | $ | 757 | $ | 65 | $ | 44 | $ | 38 | $ | 37 | $ | 27 | $ | 29 | $ | 11 | $ | 1 | ||||||||||||||||||||||||
Goodwill additions | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||
Total assets | $ | 13,920 | $ | 13,531 | $ | 13,443 | $ | 13,237 | $ | 992 | $ | 943 | $ | 912 | $ | 858 | $ | 1,329 | $ | 1,093 | $ | 718 | $ | 763 |
(1) | Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventories. |
(2) | Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions. |
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Segmented Financial Information (continued)
Downstream | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Canadian Refined Products | U.S. Refining and Marketing | Corporate and Eliminations(1) | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 758 | $ | 831 | $ | 709 | $ | 618 | $ | 1,340 | $ | 1,043 | $ | — | $ | — | $ | (2,053 | ) | $ | (1,949 | ) | $ | (1,889 | ) | $ | (1,853 | ) | $ | 4,760 | $ | 4,351 | $ | 3,163 | $ | 3,244 | ||||||||||||||||||||||||||||||||
Costs and expenses | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 699 | 717 | 620 | 572 | 1,234 | 933 | — | — | (1,982 | ) | (1,969 | ) | (1,801 | ) | (1,790 | ) | 3,176 | 2,741 | 1,745 | 1,844 | ||||||||||||||||||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 19 | 16 | 15 | 16 | 25 | 22 | — | — | 7 | 6 | 7 | 5 | 462 | 471 | 440 | 433 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | 1 | — | — | 40 | 46 | 22 | 21 | 40 | 47 | 22 | 21 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | 6 | (20 | ) | (36 | ) | (1 | ) | 6 | (20 | ) | (36 | ) | (1 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
718 | 733 | 635 | 588 | 1,259 | 956 | — | — | (1,929 | ) | (1,937 | ) | (1,808 | ) | (1,765 | ) | 3,684 | 3,239 | 2,171 | 2,297 | |||||||||||||||||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 40 | 98 | 74 | 30 | 81 | 87 | — | — | (124 | ) | (12 | ) | (81 | ) | (88 | ) | 1,076 | 1,112 | 992 | 947 | ||||||||||||||||||||||||||||||||||||||||||||||||
Current income taxes | 4 | (2 | ) | 7 | 8 | 14 | 14 | — | — | 28 | 22 | 27 | 25 | 110 | 99 | 66 | 72 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Future income taxes | (16 | ) | 33 | 14 | 2 | 16 | 19 | — | — | (41 | ) | (37 | ) | (63 | ) | (52 | ) | (108 | ) | 244 | 205 | 225 | ||||||||||||||||||||||||||||||||||||||||||||||
Net earnings (loss) | $ | 52 | $ | 67 | $ | 53 | $ | 20 | $ | 51 | $ | 54 | $ | — | $ | — | $ | (111 | ) | $ | 3 | $ | (45 | ) | $ | (61 | ) | $ | 1,074 | $ | 769 | $ | 721 | $ | 650 | |||||||||||||||||||||||||||||||||
Capital expenditures(2) | $ | 52 | $ | 77 | $ | 43 | $ | 40 | $ | 16 | $ | 5 | $ | — | $ | — | $ | 20 | $ | 8 | $ | 11 | $ | 5 | $ | 853 | $ | 722 | $ | 653 | $ | 746 | ||||||||||||||||||||||||||||||||||||
Goodwill additions | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 500 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 500 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
Total assets | $ | 1,335 | $ | 1,212 | $ | 1,304 | $ | 1,180 | $ | 3,058 | $ | 2,915 | $ | — | $ | — | $ | 370 | $ | 136 | $ | 351 | $ | 199 | $ | 21,697 | $ | 20,718 | $ | 17,969 | $ | 17,781 | ||||||||||||||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 579 | $ | 776 | $ | 674 | $ | 546 | $ | — | $ | — | $ | — | $ | — | $ | (1,691 | ) | $ | (1,876 | ) | $ | (1,756 | ) | $ | (1,598 | ) | $ | 3,084 | $ | 3,436 | $ | 3,040 | $ | 3,104 | ||||||||||||||||||||||||||||||||
Costs and expenses | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 550 | 724 | 596 | 511 | — | — | — | — | (1,671 | ) | (1,837 | ) | (1,705 | ) | (1,529 | ) | 1,845 | 2,011 | 1,708 | 1,927 | ||||||||||||||||||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 14 | 11 | 13 | 10 | — | — | — | — | 10 | 6 | 5 | 6 | 426 | 411 | 383 | 379 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | 24 | 19 | 22 | 27 | 24 | 19 | 22 | 27 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | 8 | 5 | (32 | ) | (5 | ) | 8 | 5 | (32 | ) | (5 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
564 | 735 | 609 | 521 | — | — | — | — | (1,629 | ) | (1,807 | ) | (1,710 | ) | (1,501 | ) | 2,303 | 2,446 | 2,081 | 2,328 | |||||||||||||||||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 15 | 41 | 65 | 25 | — | — | — | — | (62 | ) | (69 | ) | (46 | ) | (97 | ) | 781 | 990 | 959 | 776 | ||||||||||||||||||||||||||||||||||||||||||||||||
Current income taxes | 2 | 5 | 3 | 9 | — | — | — | — | (1 | ) | (2 | ) | 2 | 9 | 54 | 210 | 210 | 204 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Future income taxes | 3 | 8 | 10 | — | — | — | — | — | (35 | ) | (26 | ) | (12 | ) | (52 | ) | 185 | 98 | (229 | ) | 48 | |||||||||||||||||||||||||||||||||||||||||||||||
Net earnings (loss) | $ | 10 | $ | 28 | $ | 52 | $ | 16 | $ | — | $ | — | $ | — | $ | — | $ | (26 | ) | $ | (41 | ) | $ | (36 | ) | $ | (54 | ) | $ | 542 | $ | 682 | $ | 978 | $ | 524 | ||||||||||||||||||||||||||||||||
Capital expenditures(2) | $ | 83 | $ | 59 | $ | 79 | $ | 64 | $ | — | $ | — | $ | — | $ | — | $ | 14 | $ | 10 | $ | 7 | $ | 6 | $ | 893 | $ | 754 | $ | 689 | $ | 865 | ||||||||||||||||||||||||||||||||||||
Goodwill additions | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
Total assets | $ | 1,114 | $ | 1,070 | $ | 998 | $ | 883 | $ | — | $ | — | $ | — | $ | — | $ | 578 | $ | 687 | $ | 257 | $ | 114 | $ | 17,933 | $ | 17,324 | $ | 16,328 | $ | 15,855 |
(1) | Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventories. |
(2) | Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions. |
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Segmented Capital Expenditures
2007 | 2006 | |||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||
Upstream | ||||||||||||||||||||||||||||||||
Western Canada | $ | 594 | $ | 451 | $ | 433 | $ | 553 | $ | 630 | $ | 465 | $ | 397 | $ | 680 | ||||||||||||||||
East Coast Canada and Frontier | 87 | 73 | 62 | 59 | 66 | 104 | 115 | 73 | ||||||||||||||||||||||||
International | 25 | 21 | 25 | 5 | 8 | 43 | 42 | 4 | ||||||||||||||||||||||||
706 | 545 | 520 | 617 | 704 | 612 | 554 | 757 | |||||||||||||||||||||||||
Midstream | ||||||||||||||||||||||||||||||||
Upgrader | 44 | 51 | 74 | 48 | 65 | 44 | 38 | 37 | ||||||||||||||||||||||||
Infrastructure and Marketing | 15 | 36 | 5 | 36 | 27 | 29 | 11 | 1 | ||||||||||||||||||||||||
59 | 87 | 79 | 84 | 92 | 73 | 49 | 38 | |||||||||||||||||||||||||
Downstream | ||||||||||||||||||||||||||||||||
Canadian Refined Products | 52 | 77 | 43 | 40 | 83 | 59 | 79 | 64 | ||||||||||||||||||||||||
U.S. Refining and Marketing | 16 | 5 | — | — | — | — | — | — | ||||||||||||||||||||||||
68 | 82 | 43 | 40 | 83 | 59 | 79 | 64 | |||||||||||||||||||||||||
Corporate | 20 | 8 | 11 | 5 | 14 | 10 | 7 | 6 | ||||||||||||||||||||||||
$ | 853 | $ | 722 | $ | 653 | $ | 746 | $ | 893 | $ | 754 | $ | 689 | $ | 865 | |||||||||||||||||
Note: Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions.
45
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Exhibit No. | Description | |||
23 | .1 | Consent of KPMG LLP, independent accountants. | ||
23 | .2 | Consent of McDaniel and Associates Consultants Ltd., independent engineers. | ||
31 | .1 | Certification of Chief Executive Officer and Acting Chief Financial Officer pursuant toRule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934. | ||
32 | .1 | Certification of Chief Executive Officer and Acting Chief Financial Officer pursuant toRule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350). |