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U.S. SECURITIES AND EXCHANGE COMMISSION
FORM 40-F
| þ | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934. |
| o | ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended: Commission File Number:
PENGROWTH ENERGY TRUST
Alberta, Canada
(Province or other jurisdiction of incorporation or organization)
| 1311 | None | |
| (Primary Standard Industrial | (I.R.S. Employer | |
| Classification Code Number) | Identification Number) |
Suite 2900, 111 –5th Avenue S.W.
Calgary, Alberta Canada T2P 3Y6
(403) 233-0224
(Address and telephone number of Registrant’s principal executive offices)
Vinson & Elkins L.L.P.
2300 First City Tower, 1001 Fannin Street
Houston, Texas 77002-6760
(713) 758-2222
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
| Title of each class | Name of each exchange on which registered | |
| Class A Trust Units | New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
| (Title of Class) |
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Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
| (Title of Class) |
For Annual Reports indicate by check mark the information filed with this Form:
| o Annual information form | o Audited annual financial statements |
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:
There were 135,677,394 Trust Units, of no par value, outstanding as of June 30, 2004.
Indicate by check mark whether the Registrant filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, please indicate the filing number assigned to the Registrant in connection with such Rule.
| Yeso | Noþ |
Indicate by check mark whether the Registrant (1) has filed all reports 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 filing requirements for the past 90 days.
| Yesþ | Noo |
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DOCUMENTS FILED AS PART OF THIS FORM 40-F
The following documents have been filed as part of this Form 40-F as Appendices hereto:
| Appendix | Documents | |
| A | Pengrowth Energy Trust Renewal Annual Information Form for the year ended December 31, 2003. | |
| B | Management’s Discussion and Analysis (included on pages 42 through 65 of the Pengrowth Energy Trust 2003 Annual Report). | |
| C | Consolidated Financial Statements of Pengrowth Energy Trust (included on pages 66 through 97 of the Pengrowth Energy Trust 2003 Annual Report), including footnote 20 thereof which includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles. | |
| D | Five Year Review — Pengrowth Energy Trust Consolidated Financial Results (included on pages 98 through 99 of the Pengrowth Energy Trust 2003 Annual Report). | |
| E | Corporate Governance (included on pages 100 through 102 of the Pengrowth Energy Trust 2003 Annual Report). | |
| F | Part II — Corporate Governance (included on pages 12 through 21 of the Pengrowth Energy Trust Information Circular — Proxy Statement dated March 15, 2004). | |
| G | Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”. |
BACKGROUND AND STRUCTURE OF THE REGISTRANT
Disclosure regarding the background and structure of the Registrant is included on pages 8 and 9 of the Annual Information Form contained in Appendix A, which is incorporated herein.
Pengrowth Management Limited
Disclosure regarding Pengrowth Management Limited is included on pages 16 through 18 of the Annual Information Form contained in Appendix A, which is incorporated herein.
The Trust Units
Trust units are issued under the terms of a trust indenture (the “Trust Indenture”) between Pengrowth Corporation and Computershare Trust Company of Canada (“Computershare”), as trustee. A maximum of 500,000,000 trust units may be created and issued pursuant to the Trust Indenture, of which 123,873,651 trust units were outstanding on December 31, 2003 and 135,677,394 trust units were outstanding on June 30, 2004. Each trust unit represents a fractional undivided beneficial interest in the Registrant.
The Trust Indenture, among other things, provides for the establishment of the Registrant, the issue of trust units, the permitted investments of the Registrant, the procedures respecting distributions to unitholders, the appointment and removal of Computershare as trustee, Computershare’s authority and restrictions thereon, the calling of meetings of unitholders, the conduct of business at such meetings, notice provisions, the form of trust unit certificates and the termination of the Registrant. The Trust Indenture may be amended from time to time. Most amendments to the Trust Indenture, including the early termination of the Registrant and the sale or transfer of the property of the Registrant as an entirety or substantially as an entirety, require approval by an extraordinary resolution of the unitholders. An extraordinary resolution of the
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unitholders requires the approval of not less than 66 2/3% of the votes cast by unitholders at a meeting of unitholders held in accordance with the Trust Indenture at which two or more holders of at least 5% of the aggregate number of trust units then outstanding are represented. Computershare, as trustee, is permitted to amend the Trust Indenture without the consent or approval of the unitholders for certain purposes, including: (i) ensuring that the Registrant complies with applicable laws or government requirements, including satisfaction of certain provisions of theIncome Tax Act(Canada); (ii) ensuring that additional protection is provided for the interests of unitholders as Computershare may consider expedient; and (iii) making typographical or other non-substantive changes that are not adverse to the interests of Computershare or unitholders.
At a meeting of the holders of the outstanding trust units of the Registrant held on April 22, 2004, the holders of trust units approved and adopted an extraordinary resolution to amend the Trust Indenture. Pursuant to this resolution, the Trust Indenture was amended, effective as of July 12, 2004, to (i) create two classes of trust units, consisting of Class A Trust Units (“Class A Units”) and Class B Trust Units (“Class B Units”), (ii) provide that, at the Effective Time (as defined below), the existing trust units will be reclassified as Class B Units, and (iii) provide that, immediately following such reclassification, the Class B Units held by a holder that is a Non-Resident (as defined below) will be deemed to be converted into Class A Units on the basis of one Class A Unit for each Class B Unit held. The “Effective Time” means 5:00 p.m. (eastern time) on the date determined by the Board of Directors of Pengrowth Corporation for the reclassification of the trust unit capital of the Registrant to become effective, which date has been determined by such Board of Directors to be July 27, 2004. “Non-Resident” means a non-resident of Canada for the purposes of the Income Tax Act (Canada).
Upon the reclassification of the existing trust units into Class B Units and the conversion of Class B Units held by Non-Resident into Class A Units (collectively, the “Reclassification Transactions”), the Registrant will have outstanding two classes of trust units in the capital of the Registrant under the Trust Indenture: Class A Trust Units and Class B Trust Units. Both classes of trust units will have the same rights in relation to voting, obtaining distributions and obtaining assets upon the wind-up or dissolution of the Registrant. The only principal distinction between the two classes of units will be in respect of the residency of the persons entitled to hold and trade the Class A and Class B Trust Units. The Class A Units will not be subject to any residency restriction and may be exchanged at any time for Class B Trust Units (provided that the holder provides a suitable declaration that the holder is not a Non-Resident) and will be subject to a restriction on the number to be issued such that the number of issued and outstanding Class A Trust Units will not exceed 99% (the “Ownership Threshold”) of the number of issued and outstanding Class B Trust Units (subject to certain transitional provisions). The Registrant has applied to list the Class A Units on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange (“NYSE”). The Class B Units may not be held by non-residents of Canada, and may be exchanged by holder for Class A Units, provided that the Ownership Threshold will not be exceeded. The Registrant has applied to list the Class B Units on the TSX. The Class B Units will not be listed on the NYSE.
The following procedures have been adopted by the Registrant and the Trustee to monitor and constrain the ownership of Class B Trust Units by Non-Residents:
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| • | Canadian Depository for Securities Limited (“CDS”) will be advised that it is prohibited from holding Class B Units on behalf of non-residents. Pengrowth Corporation will require participants in the book-based system to provide a participant declaration on a periodic basis to ensure that no non-resident of Canada owns any Class B Units; | |||
| • | Depository Trust Company (“DTC”) will not be permitted to hold Class B Units; | |||
| • | the number of issued and outstanding Class A Units will be monitored to ensure the number of such limits does not exceed 99% of the number of issued and outstanding Class B Units (after the initial implementation period); | |||
| • | Class B Units may be exchanged for Class A Units. However, Pengrowth Corporation will implement a reservation system pursuant to which a reservation number must be obtained for the conversion of Class B Units to Class A Units; | |||
| • | Class A Units may be exchanged for Class B Units provided that the transferee provides a declaration that the transferee is not a Non-Resident; and | |||
| • | Class A Units will be registered with CDS, DTC and Computershare in the same manner as the registered and book based system which currently operates in respect of trust units. | |||
These rules and procedures may be amended from time to time by the Registrant and Computershare, as trustee.
If it appears from the securities registers, or if the Board of Directors determines that the number of issued and outstanding Class A Units exceeds the Ownership Threshold, the Registrant may make a public announcement of the contravention and may refuse to accept subscriptions for Class A Units or accept conversions of Class B Units into Class A Units. In addition, if the Board of Directors determines that it would not be unfairly prejudicial to, and would not unfairly disregard the interests of, persons beneficially owning or controlling Class A Units, the Registrant shall send a notice to the registered holders of Class A Units chosen on the basis of inverse order of registration requiring such holders to dispose of their Class A Units and, pending such disposition, may suspend the rights of ownership attached to such units. Any such disposition notice would specify in reasonable detail (i) the nature of the contravention of the Ownership Threshold, (ii) the number of excess Class A Units, (iii) a date, which shall not be less than 60 days after the date of notice, by which the Class A Units are not to be (A) sold or otherwise disposed of to a person who is not a Non-Resident and who concurrently agrees to convert such units into Class B Units or (B) if the holder is not a Non-Resident, converted into Class B Units and (iv) state that unless the holder complies, the Registrant may sell or redeem the excess Class A Units held by such holder. If a holder of Class A Units fails to comply with such notice, the Registrant may elect to sell, on behalf of the registered holder, the excess Class A Units on their principal stock exchange and pay to the holder the net proceeds of the sale after deduction of any commission, tax or other costs of sale.
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If the holder fails to comply with the notice, and the Registrant determines that a sale of the excess Class A Units would be impracticable or have a material adverse effect on the market value of the Class A Units, the Registrant may elect to repurchase or redeem the excess Class A Units, without providing further notice. The repurchase or redemption price to be paid for such excess Class A Units will be the 10 day average closing price of the Class B Units on their principal stock exchange.
Exclusionary Offer
If an offer is made to purchase Class A Units that must, by reason of securities legislation or stock exchange requirements, be made to all or substantially all of the owners of Class A Units and such offer is not made concurrently with an offer to purchase Class B Units that is identical to the offer to purchase Class A Units in terms of price per trust unit and in all other material respects, then each outstanding Class B Unit shall be convertible into one Class A Unit at the option of the holder thereof from the day the offer is made until the expiry date of the offer. In these circumstances, the Ownership Threshold would not apply in respect of the Class A Units. An election of the holder of Class B Units to exercise this conversion right shall also be deemed to also constitute the irrevocable election by the holder to deposit such units pursuant to the offer and to exercise a right of the holder to convert such units back into Class B Units if such units are not taken up and paid for under the offer.
However, the Trust Indenture restricts the coat-tail provisions to ensure that the Ownership Threshold is not violated by providing that, in respect of exclusionary offers made for only one class of Trust Units,
| (i) | holders of Class A Units do not have the right to convert Class A Units to Class B Units where an exclusionary offer is made for the Class B Units if the offeror is a Non-Resident (this would not be a valid offer because a Non-Resident is not permitted to hold Class B Units); | |||
| (ii) | where Class B Units are converted to Class A Units upon an exclusionary offer being made for the Class A Units, those units will be immediately converted back to Class B Units upon being taken up and paid for to preserve the relative number of Class A Trust Units and Class B Trust Units outstanding both before and after the bid; | |||
| (iii) | if a Non-Resident acquires 10% or more of the outstanding Class A Units (including Class A Units issued on the conversion of Class B Units) the Non-Resident shall not be entitled to vote or receive distributions in respect to all of such units. These sanctions provide a strong disincentive for a non-resident to make an exclusionary offer for Class A Units; | |||
| (iv) | if Class A Units or Class B Units are tendered to an exclusionary offer for the Class B Units or the Class A Units, respectively, the deemed conversion of such units is delayed until the take-up of the units pursuant to the offer and not before; and | |||
| (v) | if an exclusionary offer is withdrawn or expires, or trust units that are tendered to an exclusionary offer are withdrawn, no conversion will occur. | |||
The Trustee
Computershare, as trustee, is generally empowered by the Trust Indenture to exercise any and all rights and powers that could be exercised by the owner of the assets of the Registrant. Computershare’s specific responsibilities include, but are not limited to, the following: (i) reviewing and accepting subscriptions for trust units and issuing trust units subscribed for; (ii) subscribing for royalty units of the Registrant (“Royalty Units”); (iii) issuing trust units in exchange for Royalty Units tendered to it for exchange; and (iv) maintaining records and providing timely reports to unitholders. Computershare is authorized to delegate its powers and duties as trustee except as prohibited by law. Specific powers are delegated to Pengrowth Corporation as “Administrator” under the Trust Indenture and Computershare has granted broad discretion to Pengrowth Management Limited to administer and regulate the day to day operations of the Registrant.
Computershare, as trustee, must exercise its powers and carry out its functions under the Trust Indenture honestly, in good faith and in the best interests of the Registrant and the unitholders, and must exercise that degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. Computershare is not required to devote its entire time to the business and affairs of the Registrant.
Computershare, as trustee, shall be reappointed or replaced every two years as may be determined by a majority of the votes cast at an annual meeting of the unitholders. Computershare may resign upon 60 days notice to Pengrowth Corporation. Computershare may be removed by extraordinary resolution of the unitholders or by Pengrowth Corporation in certain specific circumstances. Such resignation or removal shall become effective upon the acceptance of appointment by a successor.
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Redemption Right
The Class A Units and Class B Units (collectively “Trust Units”) are redeemable by Computershare, as trustee, at the request of a unitholder when properly endorsed for transfer and when accompanied by a duly completed and properly executed notice requesting redemption. The redemption right permits unitholders in the aggregate to redeem Trust Units for maximum proceeds of $25,000 in any calendar month; provided that such limitation may be waived at the discretion of the Board of Directors. The redemption price is the lesser of: (i) 95% of the market price of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 day trading period commencing immediately after the date on which the Trust Units are surrendered for redemption; and (ii) the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units are surrendered for redemption. Following the Reclassification Transactions, the redemption price for both Class A Units and Class B Units will be determined in reference to the principal market for the Class B Units.
Right to Exchange Royalty Units for Trust Units
Holders of Royalty Units have the right under the Trust Indenture to exchange their Royalty Units for Trust Units. Pursuant to the amendments to the Trust Indenture approved and adopted by the unitholders on April 22, 2004, a holder of Royalty Units who is a Non-Resident may exchange Royalty Units only for Class A Units and not Class B Units, and a holder of Royalty Units who is not a Non-Resident will be able to exchange Royalty Units for Class A Units or Class B Units, subject in both cases to the terms, conditions and limitations in the Trust Indenture. A holder of Royalty Units wishing to exchange any or all of his Royalty Units for Class A Units would be able to do so only if and to the extent that the number of Class A Units issued and outstanding at the particular time is not greater than the Ownership Threshold and will not exceed the Ownership Threshold as a result of the exchange. A holder of Royalty Units wishing to exercise his right to exchange any or all of his Royalty Units for Class B Units will be required to submit a unitholder’s declaration stating that the beneficial owner of the Royalty Units is not a Non-Resident. A holder of Royalty Units applying to exchange Royalty Units for Trust Units will be required to elect and indicate irrevocably at that time:
| (a) | how many Royalty Units he wishes to exchange; | |||
| (b) | how many Class A Units and Class B Units respectively he wishes to receive upon the exchange; | |||
| (c) | whether, if having regard to the Ownership Threshold fewer Class A Units are available than the number that he has requested to receive upon the exchange, he wishes to receive the small number and to retain the balance of his Royalty Units; and | |||
| (d) | whether, if Class A Units are not available, he elects and is entitled by virtue of not being a Non-Resident to receive Class B Units instead. | |||
The Registrant, together with its transfer agent, may from time to time establish procedures for recognizing the priorities of requested exchanges of Royalty Units for Class A Units and requests for conversions of Class B Units into Class A Units, which procedures may, but are not required to, apply a reservation or waiting list system to holders of Royalty Units and Class B Units whose requests to exchange Royalty Units for Class A Units and to convert Class
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B Units into Class A Units are refused due to the approach of the number of Class A Units issued and outstanding to the Ownership Threshold.
Voting at Meetings of the Registrant
Meetings of holders of Class A Units and holders of Class B Units (collectively “Unitholders”) may be called on 21 days notice (subject to the requirements of applicable securities laws) and may be called at any time by Computershare, as trustee, or upon written request of Unitholders holding in the aggregate not less than 5% of the Trust Units, and shall be called by Computershare and held annually. All activities necessary to organize any such meeting will be undertaken by Pengrowth Corporation on behalf of Computershare. At all meetings of the Unitholders, each holder is entitled to one vote in respect of each trust unit held. Unitholders may attend and vote at all meetings of the Unitholders either in person or by proxy and a proxy holder need not be a unitholder. Two persons present in person either holding personally or representing as proxies at least 5% of the outstanding Trust Units constitute a quorum for the transaction of business at all such meetings. Except as otherwise provided in the Trust Indenture, matters requiring the approval of the Unitholders must be approved by extraordinary resolution.
Unitholders are entitled to pass resolutions that will bind Computershare, as trustee, with respect to a limited list of matters, including but, not limited to, the following: (i) the removal or appointment of Computershare as trustee; (ii) the removal or appointment of the auditor of the Registrant; (iii) the amendment of the Trust Indenture; (iv) the approval of subdivisions or consolidations of Trust Units; (v) the sale of the assets of the Registrant as an entirety or substantially as an entirety; and (vi) termination of the Registrant.
Unitholders can also consider the appointment of an inspector to investigate whether Computershare has performed its duties arising under the Trust Indenture. Such an inspector shall be appointed if a resolution approving the appointment of such inspector is passed by a majority of the votes duly cast at a meeting held for that purpose.
Voting at Meetings of Pengrowth Corporation
The Unitholders, along with holders of Royalty Units other than Computershare, as trustee, are entitled to voting rights at meetings of shareholders of Pengrowth Corporation on the basis of one vote for each Trust Unit (or Royalty Unit) held.
Termination of the Registrant
The Unitholders may vote to terminate the Registrant at any meeting of the Unitholders, subject to the following:
| (i) | a vote may be held only if requested in writing by the holders of not less than 25% of the Trust Units, or if the Trust Units have become ineligible for investment by RRSPs, RRIFs, RESPs and DPSPs; | |||
| (ii) | the termination must be approved by extraordinary resolution of the Unitholders; and | |||
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| (iii) | a quorum representing 5% of the issued and outstanding Trust Units must be present or represented by proxy at the meeting at which the vote is taken. |
If the Unitholders approve termination, Computershare, as trustee, will sell the assets of the Registrant, discharge all known liabilities and obligations, and distribute the remaining assets to the Unitholders. Computershare will distribute directly to the Unitholders any assets which Computershare is unable to sell by the date set for termination.
Unitholder Limited Liability
The Trust Indenture, provides that no unitholder will be subject to any personal liability in connection with the Registrant or its obligations and affairs, and the satisfaction of claims of any nature arising out of or in connection therewith is only to be made out of the Registrant’s assets. Additionally, the Trust Indenture states that no unitholder is liable to indemnify or reimburse Computershare for any liabilities incurred by Computershare with respect to any taxes payable by or liabilities incurred by the Registrant or Computershare, and all such liabilities will be enforceable only against, and will be satisfied only out of, the Registrant’s assets. It is intended that the operations of the Registrant will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the Unitholders for claims against the Registrant.
TheIncome Trusts Liability Actwas proclaimed in force effective July 1, 2004. The Act applies to Alberta income trusts, which include the Registrant by virtue of being a trust governed by the laws of the Province of Alberta and being a reporting issuer under theSecurities Act(Alberta). The legislation protects Unitholders of income funds and royalty trusts from the legal uncertainties regarding the potential liability of Unitholders. However, the Act does not affect the liability of Unitholders with respect to any act, default, obligation or liability that arose before July 1, 2004 and there is a risk that a unitholder could be personally liable for obligations of the Registrant arising before that date that are not satisfied by the Registrant.
Special Voting Unit
The authorized Trust Units include the special voting trust unit which entitles the holder thereof to a number of votes equal to the number of outstanding exchangeable shares of Pengrowth Corporation at any meeting of the Unitholders. The special voting trust unit is not entitled to receive distributions from the Registrant. The special voting trust unit is intended to provide voting rights to the holders of exchangeable shares of Pengrowth Corporation equivalent to the voting rights attached to Trust Units. As of the date hereof, the special voting trust unit has not been issued and there are no issued and outstanding exchangeable shares.
The Royalty Indenture
Disclosure regarding the royalty indenture of the Registrant and the Royalty Units issued thereunder is included on pages 39 through 40 of the Annual Information Form contained in Appendix A, which is incorporated herein. Disclosure regarding exchangeable shares of Pengrowth Corporation, which may be entitled under certain circumstances to payments from assets subject to the royalty created by the royalty indenture, is included on pages 14 through 15 of the Annual Information Form contained in Appendix A, which is incorporated herein.
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CERTAIN INCOME TAX CONSIDERATIONS
Certain Canadian Federal Income Tax Considerations
In the opinion of Bennett Jones LLP, Canadian legal counsel to the Registrant, the following summary describes the principal Canadian federal income tax considerations generally applicable to a unitholder who acquires, holds and disposes of trust units of the Registrant and who, for the purposes of theIncome Tax Act(Canada) (the “Tax Act”), holds the trust units as capital property, deals at arm’s length with the Registrant and is neither resident nor deemed to be resident in Canada for the purposes of the Tax Act and any applicable income tax treaty or convention (a “non-resident unitholder”). Generally, the trust units will be considered to be capital property to a non-resident unitholder provided that the non-resident unitholder does not hold the trust units in the course of carrying on a business and has not acquired them in one or more transactions considered to be an adventure or concern in the nature of trade. This summary is not applicable to a non-resident person that is an insurer carrying on business in Canada and elsewhere. Any such non-resident unitholder should consult its own tax advisor with respect to an investment in trust units.
This summary is based upon the provisions of the Tax Act in force as of the date hereof, the Income Tax Regulations, all specific proposals to amend the Tax Act and the Income Tax Regulations that have been publicly announced prior to the date hereof, including the March 23, 2004 Canadian federal budget (the “budget”) and counsel’s understanding of the current published administrative and assessing policies of the Canada Revenue Agency, including the advance income tax rulings obtained by the Registrant from the Canada Revenue Agency.
This summary is not exhaustive of all possible Canadian federal income tax considerations and does not take into account any changes in the law, whether by legislative, governmental or judicial action. This summary does not take into account provincial, territorial or foreign tax considerations, which may differ significantly from those discussed herein.
This summary is of a general nature only and is not intended to be legal or tax advice to any particular non-resident unitholder. Consequently, non-resident Unitholders should consult their own tax advisors with respect to their own particular circumstances.
This summary assumes that the Registrant qualifies as a “unit trust” and a “mutual fund trust” within the meaning of the Tax Act as of the date hereof, and will continue to qualify thereafter, as a mutual fund trust for the duration of its existence. In order to so qualify, there must be at least 150 Unitholders each of whom owns not less than one “block” of trust units having a fair market value of not less than $500 (Cdn.). A “block” of trust units means 100 trust units if the fair market value of one trust unit is less than $25 (Cdn.) and 25 trust units if the fair market value of one trust unit is greater than $25 (Cdn.) and less than $100 (Cdn.). In order to qualify as a mutual fund trust, the Registrant cannot, and may not at any time, reasonably be considered to be established or maintained primarily for the benefit of non-resident persons. In addition, the undertaking of the Registrant must be restricted to the investing of its funds in property (other than real property or an interest in real property), the acquiring, holding, maintaining, improving, leasing or managing of any real property (or interest in real property) that is capital property of the Registrant, or a combination of these activities. This summary
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assumes that these requirements will be satisfied so that the Registrant will qualify as a mutual fund trust at all relevant times. In the event that the Registrant were not to qualify as a mutual fund trust, the income tax considerations would, in some respects, be materially different from those described below.
Counsel has been advised by Pengrowth Corporation that the most recent residency information received indicates that a majority of trust units of the Registrant are beneficially owned by non-resident Unitholders despite efforts by the Registrant to reduce non-resident ownership of trust units to below 50% of all trust units issued. Counsel is of the opinion that the better view is that the Registrant should qualify as a mutual fund trust as of the date hereof. However, there is some uncertainty in this regard and counsel can provide no assurance that the Registrant qualifies as a mutual fund trust given the potential that the Registrant is, or has been prior to the date hereof, maintained primarily for the benefit of non-resident persons. If the Registrant does not qualify as a mutual fund trust, a non-resident unitholder will be subject to Canadian tax on any gains realized on the disposition of trust units. In addition, if the Registrant is not a mutual fund trust, the Registrant will be subject to a special Canadian tax under Part XII.2 of the Tax Act which may have adverse tax consequences to non-resident Unitholders.Non-resident Unitholders are urged to read “Risk Factors — If the Registrant ceases to qualify as a mutual fund trust it would adversely affect the value of our trust units” in the 2004 Annual Information Form of the Registrant dated May 17, 2004 for further details regarding the Registrant not qualifying as a mutual fund trust.
Taxation of the Registrant
The Registrant is subject to taxation in each taxation year on its income or loss for the year as though it were a separate individual. The taxation year of the Registrant is the calendar year.
The Registrant will be required to include in its income for each taxation year all amounts that it receives in respect of the royalty paid by Pengrowth Corporation, any interest on indebtedness owed by Pengrowth Corporation to it and any other interest in respect of its other investments that accrues to the Registrant to the end of the year, or becomes receivable or is received by it before the end of the year, except to the extent that such amount was included in computing its income for a preceding taxation year. Other types of income from the Registrant’s investments, including its oil and natural gas facilities, is generally required to be included in its income on an accrual basis. Proposed amendments to the Tax Act will require the Registrant to include income on the royalty paid from Pengrowth Corporation on an accrual basis.
In computing its income for tax purposes, the Registrant may deduct reasonable administrative expenses, capital cost allowance in respect of its oil and natural gas facilities in an amount generally equal to the lesser of the prescribed rate and the net leasing income attributable to such property, an amount not exceeding 10% of its cumulative Canadian oil and gas property expense account, determined on a declining balance basis, 20% of the total issue expenses of offerings of trust units to the extent that the expenses were not otherwise deductible in a preceding year and amounts in respect of a resource allowance and/or deductible Crown charges computed in accordance with the rules contained in the Tax Act.
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The Registrant will be entitled to deduct from its income for a taxation year otherwise determined, after taking into account the inclusions and deductions outlined above, the portion thereof that is paid or becomes payable in the year to Unitholders, including the amount which constitutes the excess, if any, of reimbursed Crown charges paid by the Registrant over the resource allowance deductible for the year to the extent that such excess amount is designated to the Unitholders for that year. In accordance with the terms of the Trust Indenture between Pengrowth Corporation and Computershare, as trustee, Computershare has agreed to designate the full amount of such excess amount annually in favour of Unitholders. An amount will be considered to be payable to a unitholder in a taxation year if it is paid in the year by the Registrant or the unitholder is entitled in the year to enforce payment of the amount. The Trust Indenture provides that Computershare, on behalf of the Registrant, shall claim the maximum permissible deductions for the purposes of computing the income of the Registrant pursuant to the Tax Act to the extent required to reduce the taxable income of the Registrant to nil or to the extent desirable in the best interests of Unitholders. As a result, Computershare may choose not to claim all deductions in computing income and taxable income to the maximum extent permitted by the Tax Act in order to utilize losses from prior taxation years.
Taxation of Non-Residents Unitholders
Any distribution of income of the Registrant to a non-resident unitholder will be subject to Canadian withholding tax at a rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the non-resident unitholder’s country of residence. For example, pursuant to theCanada — United States Income Tax Convention, 1980(the “Canada-U.S. Tax Treaty”), residents of the United States for the purposes of such treaty will be entitled to have the rate of withholding generally reduced to 15% of the amount of any distribution of income. To the extent that Canadian withholding tax is applied to the non-taxable portion of a distribution made on or before December 31, 2004, non-resident Unitholders (or their agent) may apply for a refund of such Canadian withholding tax by filing Canada Revenue Agency Form NR7-R “Application for Refund of Non-Resident Tax Withheld” no later than two years after the end of the calendar year in which the Registrant has paid the distribution.
The budget proposes a new 15% Canadian withholding tax on the non-taxable portion of the Registrant’s distributions, which, under the current provisions of the Tax Act, are not subject to any Canadian withholding tax. The budget proposes that the new 15% Canadian withholding tax be applicable to distributions made by the Registrant after 2004. The new 15% Canadian withholding tax will only apply if, at the time of the distribution, trust units of the Registrant are listed on a prescribed stock exchange (which includes the Toronto Stock Exchange) and the value of the trust units is primarily attributable to real property situated in Canada, Canadian resource property (which includes the royalty payable by Pengrowth Corporation to the Registrant) or a timber resource property. If a subsequent disposition of a trust unit results in a capital loss to a non-resident unitholder, a refund of the new 15% Canadian withholding tax is available in limited circumstances, subject to the filing of a special Canadian tax return.
The budget also proposes a 25% withholding tax on distributions made to non-resident Unitholders which are attributable to capital gains realized by the Registrant after March 22, 2004 on the disposition of taxable Canadian property where the Registrant has made certain designations on such capital gains with respect to its Unitholders. The 25% rate of Canadian
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withholding tax may be reduced pursuant to the terms of an applicable income tax treaty between Canada and the non-resident unitholder’s country of residence. For non-resident Unitholders who are residents of the United States for the purposes of the Canada-U.S. Tax Treaty, the rate of withholding is generally reduced to 15%.
A disposition or deemed disposition of trust units of the Registrant, whether on redemption, by virtue of non-taxable distributions in excess of a non-resident unitholder’s adjusted cost base, or otherwise, will not give rise to any capital gain subject to tax under the Tax Act to a non-resident unitholder provided that such trust units do not constitute taxable Canadian property under the Tax Act. Trust units of a non-resident unitholder will not generally be considered to be “taxable Canadian property” unless either: (i) at any time during the period of five years immediately preceding the disposition of trust units by such non-resident unitholder, not less than 25% of the issued trust units were owned by the non-resident unitholder, by persons with whom the non-resident unitholder did not deal at arm’s length or by any combination thereof; (ii) the Registrant ceases to qualify as a mutual fund trust; or (iii) the non-resident unitholder’s trust units are otherwise deemed to be taxable Canadian property.
The cost of a trust unit to a non-resident unitholder will generally be the aggregate of the subscription price thereof and reasonable acquisition costs computed in Canadian dollars. In determining the adjusted cost base of a trust unit, a non-resident unitholder will be required to deduct any non-taxable distributions made on or prior to December 31, 2004 in respect of such trust unit. The cost of trust units acquired by a non-resident unitholder will generally be required by the Tax Act to be averaged with the adjusted cost base of all other trust units which are held by such non-resident unitholder as capital property immediately prior to such acquisition for the purpose of determining the adjusted cost base of all such trust units at any time after such acquisition. To the extent that the adjusted cost base of a trust unit to a non-resident unitholder would otherwise be less than nil, the negative amount will be deemed to be a capital gain realized by the non-resident unitholder from the disposition of the trust unit in the year in which the negative amount arises. For the purposes of computing a non-resident unitholder’s adjusted cost base of a trust unit after 2004, the budget proposes that a distribution paid in respect of a trust unit which is subject to the new 15% Canadian withholding tax will not reduce the adjusted cost base of such trust unit to a non-resident unitholder.
Certain United States Federal Income Tax Considerations
The following is a summary of all the material United States federal income tax consequences that generally would apply to a unitholder who is a United States person, with respect to the ownership and disposition of trust units. This description is based on the Internal Revenue Code of 1986 (United States), as amended (the “Code”), existing regulations promulgated thereunder, and judicial and administrative interpretations thereof, all as in effect on the date hereof and all of which are subject to change either prospectively or retroactively. Unless otherwise noted, all statements of legal conclusions contained in this discussion represent the opinion of Vinson & Elkins L.L.P., United States legal counsel for the Registrant. That opinion is based in part upon the accuracy and completeness of certain factual representations made by us to Vinson & Elkins L.L.P. The tax treatment of an owner of our trust units may vary depending upon his particular situation. Certain owners (including persons that are not United States persons, banks, insurance companies, tax-exempt organizations, financial institutions,
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persons whose functional currency is not the United States dollar, persons subject to the alternative minimum tax and broker-dealers) may be subject to special rules not discussed below. The following summary is limited to investors who will own the trust units as “capital assets” within the meaning of the Code. The discussion below does not address the effect of any state, local or foreign tax law on an owner of the trust units. Purchasers of trust units are urged to consult with their own tax advisors with respect to circumstances peculiar to them that could affect the U.S. federal income tax treatment of their investment in the trust units.
As used herein, the term “United States person” means an individual who is a citizen or resident of the United States, a partnership, corporation or other entity organized in or under the laws of the United States or any state thereof, an estate that is subject to United States federal income taxation without regard to the source of its income or a trust if a United States court has primary supervision over its administration and one or more United States persons have the authority to control all substantial decisions of the trust.
Classification of the Registrant as a Partnership
The Registrant has elected under applicable Treasury Regulations to be treated as a partnership for United States federal income tax purposes. The application of these regulations is unclear in certain respects and no rulings have been requested from the United States Internal Revenue Service (the “IRS”) with respect to the United States federal income tax treatment of the Registrant or other matters regarding the Registrant except the Registrant received a ruling from the IRS regarding the timeliness of its partnership election. Although there is no plan or intention to do so, the Registrant has the right to elect under applicable Treasury Regulations to be treated as a corporation for United States federal income tax purposes if such election was determined to be beneficial.
A partnership generally is not treated as a taxable entity and incurs no United States federal income tax liability. Instead, as discussed below, each partner in an entity treated as a partnership for tax purposes is required to take into account his share of partnership income, gain, loss and deduction in computing his federal income tax liability, regardless of whether cash or other distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of any cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest. Each owner of trust units will be treated as a partner in the Registrant.
Section 7704 of the Code provides that entities treated as publicly-traded partnerships such as the Registrant will, as a general rule, be taxed as corporations. However, an exception (the “qualifying income exception”) exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes interest (from other than a financial business), dividends, rents from real property, and income and gains derived from the exploration, development, mining, production, processing, refining, transportation, or marketing of oil and gas. In the opinion of Vinson & Elkins L.L.P., income with respect to the royalty units issued by Pengrowth Corporation, to the extent attributable to qualifying income, will itself be treated as qualifying income. The income of Pengrowth Corporation is expected to consist primarily of income and gains derived from activities with respect to oil and gas that will result in qualifying income.
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Moreover, Pengrowth Corporation has entered into (and intends to continue entering into) hedging transactions to protect the value of the royalty payments that it anticipates making to the Registrant. Based on certain factual representations relating to such transactions, Vinson & Elkins L.L.P. is of the opinion that income from such transactions should constitute qualifying income.
We estimate that less than 5% of the Registrant’s current gross income is not qualifying income; however, this estimate could change from time to time. No assurance can be given that the qualifying income exception will in fact be met in future taxable periods. Based on and subject to this estimate, certain factual representations made by the Registrant and the legal conclusions discussed above, Vinson & Elkins L.L.P. is of the opinion that at least 90% of the current gross income of the Registrant constitutes qualifying income. The opinion of Vinson & Elkins L.L.P. is based upon factual representations made to them by the Registrant that:
| (a) | The Registrant has not elected to be treated as a corporation for U.S. tax purposes and | |||
| (b) | For each taxable year since the effective date of the election by the Registrant to be treated as a partnership for U.S. tax purposes more than 90% of the gross income of the Registrant has been gross income that Vinson & Elkins L.L.P. has opined or will opine should be qualifying income within the meaning of Section 7704(d) of the Code. | |||
Possible Classification as a Corporation; PFIC
If the Registrant fails to meet the qualifying income exception (other than a failure that is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery), the Registrant will be treated as if it had transferred all of its assets (subject to liabilities) to a newly formed corporation (on the first day of the year in which it fails to meet the qualifying income exception) in return for stock in that corporation, and then distributed that stock to the owners of our trust units in liquidation of their interests in the Registrant. That deemed transfer and liquidation would likely be taxable to the Unitholders. Thereafter, the Registrant would be treated as a corporation for United States federal income tax purposes.
If the Registrant were treated as a corporation in any taxable year, either as a result of a failure to meet the qualifying income exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the Unitholders, and our net income sourced in the United States would be taxed to us at corporate rates. Moreover, Unitholders would be taxed upon the receipt of distributions, as either taxable dividend income (to the extent of the Registrant’s current or accumulated earnings and profits calculated by reference to the Registrant’s tax basis in its assets without regard to the price paid for trust units by subsequent Unitholders) or (in the absence of earnings and profits) a non-taxable return of capital (to the extent of the unitholder’s tax basis in the trust units) or taxable capital gain (after the unitholder’s tax basis in the trust units is reduced to zero). In addition, the benefits of the Section 754 election under the Code would no longer be available to purchasers in the marketplace. See “Tax Consequences of Trust Unit Ownership — Section 754 Election”. Accordingly, taxation as a corporation could result in a material reduction in a unitholder’s cash
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flows and after-tax return and thus would likely result in a substantial reduction of the value of the trust units. In addition, should the Registrant be treated as a corporation, it is possible that it would be a considered a passive foreign investment company (“PFIC”), in which case special rules (discussed below), potentially quite adverse to U.S. persons, would apply.
Consequences of Possible PFIC Classification
A non-United States entity treated as a corporation for United States federal income tax purposes will be a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to the applicable “look through” rules, either (1) at least 75 percent of its gross income is “passive” income (the “income test”) or (2) at least 50 percent of the average value of its assets is attributable to assets that produce passive income or are held for the production of passive income (the “assets test”).
Based upon factual representations made by the Registrant concerning, among other things, the nature of its assets, income and operations, Vinson & Elkins L.L.P. is of the opinion that the Registrant, if classified as a corporation, would not be a PFIC. There are, however, legal uncertainties involved and, in addition, there is no assurance that the nature of the Registrant’s assets, income and operations will continue in the same manner. Therefore, no assurance can be given that the Registrant is not now, and will not be in the future, a PFIC.
If the Registrant were classified as a PFIC, for any year during which a unitholder owns trust units, he will generally be subject to special rules (regardless of whether the Registrant continues to be a PFIC) with respect to (1) any “excess distribution” (generally, any distribution received by him on trust units in a taxable year that is greater than 125 percent of the average annual distributions received by him in the three preceding taxable years or, if shorter, his holding period for the trust units) and (2) any gain realized upon the sale or other disposition of trust units. Under these rules:
| • | the excess distribution or gain will be allocated ratably over the unitholder’s holding period; | |||
| • | the amount allocated to the current taxable year and any year prior to the first year in which the Registrant was a PFIC will be taxed as ordinary income in the current year; | |||
| • | the amount allocated to each of the other taxable years in the unitholder’s holding period will be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year; and | |||
| • | an interest charge for the deemed deferral benefit will be imposed with respect to the resulting tax attributable to each such other taxable year. | |||
Certain elections may be available to a unitholder if the Registrant was classified as a PFIC. The Registrant will provide Unitholders with information concerning the potential availability of such elections if it determines that it is or will become a PFIC.
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The discussion below is based on the assumption, consistent with the opinion of Vinson & Elkins L.L.P. as discussed above, that the Registrant will be treated as a partnership for United States federal income tax purposes.
Tax Consequences of the Reorganization of Trust Unit Capital
Vinson & Elkins L.L.P. is of the opinion that the reorganization of trust unit capital should be a non-taxable event for U.S. federal income tax purposes. Thus, for U.S. federal income tax purposes, a holder of trust units at the effective time should recognize no income or loss, and such Unitholders’ tax bases and holding periods in their trust units should be unaffected, as a result of the reclassification. Moreover, the Registrant should not terminate as a partnership for U.S. federal income tax purposes as a result of reclassification and thus should be treated as a continuation of the partnership represented by the trust for U.S. federal income tax purposes. See "— Disposition of Trust Units — Constructive Termination.”
Notwithstanding the foregoing, a unitholder that owns directly, or indirectly, after the application of certain constructive ownership rules, trust units with a value exceeding U.S.$100,000 may be required to file Internal Revenue Service Form 8865 with his tax return for the taxable year that includes the effective time of the reclassification. Significant penalties may apply for failing to satisfy this filing requirement and thus such a U.S. holder is advised to contact his tax advisor to determine the application of this filing requirement under his own circumstances.
Tax Consequences of Trust Units Ownership
Flow-through of Taxable Income.We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share (based generally on the percentage of our trust units owned by that unitholder) of the income, gains, losses and deductions of the Registrant without regard to whether corresponding cash distributions are received by him. Consequently, a unitholder may be allocated income from the Registrant even if he has not received a cash distribution from the Registrant. Each unitholder will be required to include in income his share for the taxable year of the Registrant ending with or within the taxable year of the unitholder.
The Registrant intends to make available to each unitholder, within 75 days after the close of each calendar year, specific tax information, including a Schedule K-1, containing his share of our income, gain, loss and deduction for our preceding taxable year.
The Registrant treats the royalty between it and Pengrowth Corporation as a royalty interest for all legal purposes, including United Stated federal income tax purposes. Vinson & Elkins L.L.P. has advised the Registrant that, based upon existing authorities, this treatment is supportable. However, the royalty indenture between Pengrowth Corporation and Computershare, as trustee, in some respects differs from more conventional “net profits” interests as to which the courts and the IRS have ruled, and as a result the matter is not free from doubt. It is possible that the IRS could contend, for example, that the Registrant should be considered to have a working interest in the properties of Pengrowth Corporation. If the IRS were successful in making such a contention, the United States federal income tax consequences to Unitholders
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could be different, perhaps materially worse, than indicated in the discussion herein, which generally assumes that the royalty indenture will be respected as a royalty.
Treatment of Distributions.Cash distributions by the Registrant to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his trust units immediately before the distribution. Cash distributions made by us to a unitholder in excess of his tax basis generally will be considered to be gain from the sale or exchange of the trust units, taxable in accordance with the rules described under “Disposition of Trust Units” below.
Basis of Trust Units.A unitholder’s initial tax basis for his trust units will be the amount he paid for the trust units. That basis will be increased by his share of the Registrant income and decreased (but not below zero) by distributions to him from the Registrant, by his share of the Registrant losses and deductions, and by his share of expenditures of the Registrant that are not deductible in computing its taxable income and are not required to be capitalized. See “Disposition of Trust Units — Recognition of Gain or Loss.”
Limitations on Deductibility of Losses.Although we do not expect losses, the deduction by a unitholder of his share of any losses of the Registrant will be limited to the tax basis in his trust units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to the Registrant’s activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a trust unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.
In general, a unitholder will be at risk to the extent of the tax basis in his trust units, reduced by any amount of money he borrows to acquire or hold his trust units if the lender of those borrowed funds owns an interest in the Registrant, is related to a person that owns an interest in the Registrant (other than the unitholder whose at risk amount is being considered), or can look only to the trust units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of his trust units increases or decreases.
The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately to each entity such as the Registrant which is treated as a publicly-traded partnership. Consequently, any passive losses generated by the Registrant will only be available to offset passive income generated in the future by the Registrant and will not
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be available to offset income from other passive activities or investments, including the Registrant investments or investments in other publicly-traded partnerships, or salary or active business income. Similarly, a unitholder’s share of net income from the Registrant may be offset by any suspended passive losses from the Registrant, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other entities treated as publicly-traded partnerships. Passive losses that are not deductible because they exceed a unitholder’s share of income may be deducted in full when he disposes of his entire investment in the Registrant in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.
Limitations on Interest Deductions.The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of such taxpayer’s “net investment income.” Investment interest expense includes (i) interest on indebtedness properly allocable to property held for investment, (ii) our interest expense attributable to portfolio income, and (iii) the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income. The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or own trust units. Net investment income includes gross income from property held for investment and amounts treated as portfolio income pursuant to the passive loss rules less deductible expenses (other than interest) directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its Unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
Section 754 Election.The Registrant has made the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. The election will generally require the Registrant, in the case of a sale of the trust units in the secondary market, to adjust the purchaser’s tax basis in the assets of the Registrant pursuant to Section 743(b) of the Code to reflect his purchase price. This election does not apply to a person who purchases trust units directly from the Registrant.
A Section 754 election is advantageous if the subsequent purchaser’s tax basis in his trust units is higher than his share of the aggregate tax basis to the Registrant of the assets of the Registrant immediately prior to the purchase. In such a case, as a result of the election, the purchaser would have a higher tax basis in his share of the assets of the Registrant for purposes of calculating depletion and depreciation. Conversely, a Section 754 election is disadvantageous if the subsequent purchaser’s tax basis in such trust units is lower than his share of the aggregate tax basis of the assets of the Registrant immediately prior to the purchase. Thus, the fair market value of the trust units may be affected either favorably or adversely by the election.
Foreign Tax Credits.Subject to the limitations set forth in the Code, United States persons may elect to claim a credit against their United States federal income tax liability for net Canadian income tax withheld from distributions received in respect of the trust units (see “Certain Canadian Federal Income Tax Considerations”). Unitholders will also be entitled to claim a foreign tax credit for their share of any Canadian income taxes paid by the Registrant.
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Income from the Registrant will likely constitute foreign source “passive income” for purposes of the United States foreign tax credit limitation. The rules relating to the determination of the foreign tax credit are complex and prospective purchasers are urged to consult their own tax advisors to determine whether or to what extent they would be entitled to such credit. United States persons that do not elect to claim foreign tax credits may instead claim a deduction for their shares of Canadian income taxes paid by the Registrant or withheld from distributions by the Registrant.
Tax Treatment of the Registrant Operations
Accounting Method and Taxable Year.The Registrant uses the year ending December 31 as its taxable year and has adopted the accrual method of accounting for United States federal income tax purposes. Each unitholder will be required to include in income his share of the Registrant’s income, gain, loss and deduction for the taxable year of the Registrant ending within or with the taxable year of the unitholder. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his trust units following the close of the Registrant’s taxable year but before the close of his taxable year must include his share of the Registrant income, gain, loss and deduction in income for his taxable year with the result that he will be required to report in income for his taxable year his share of more than one year of the Registrant income, gain, loss and deduction. See “Disposition of Trust Units — Allocations Between Transferors and Transferees.”
Depletion.Under the Code, a unitholder may deduct in his United States federal income tax return a cost depletion allowance with respect to the royalty units issued by Pengrowth Corporation to the Registrant. Unitholders must compute their own depletion allowance and maintain records of the adjusted basis of the royalty units for depletion and other purposes. The Registrant, however, intends to furnish each unitholder with information relating to this computation.
Cost depletion is calculated by dividing the adjusted basis of a property by the total number of units of oil or gas expected to be recoverable therefrom and then multiplying the quotient by the number of units of oil and gas sold during the year. Cost depletion, in the aggregate, cannot exceed the initial adjusted basis of the property. In this connection, the Registrant intends to utilize a tax election available to it which will allow Purchasers of trust units in this offering to be entitled to depletion deductions based upon their purchase price for the trust units.
The depletion allowance must be computed separately by each unitholder for each oil and gas property, within the meaning of Section 614 of the Code. The IRS is currently taking the position that a net profits interest carved from multiple properties is a single property for depletion purposes. The royalty indenture between Pengrowth Corporation and Computershare, as trustee, burdens multiple properties. Accordingly, the Registrant intends to take the position that the properties subject to the royalty indenture constitute a single property for depletion purposes and the income from the net profits interest will be royalty income qualifying for an allowance for depletion. Vinson & Elkins L.L.P. believes this position is consistent with the policy underlying the IRS position. The Registrant anticipates that it would change this position
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if it should be determined that a different method of computing the depletion allowance is required by law.
Depreciation.The tax basis of the various depreciable assets of the Registrant will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition, of such assets.
Valuation of the Registrant’s Properties.Certain of the United States federal income tax consequences of the ownership and disposition of trust units will depend in part on the Registrant’s estimates of the relative fair market value of its assets. Although the Registrant may consult from time to time with professional appraisers regarding valuation matters, the Registrant will itself make many of the relative fair market value estimates. These estimates are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Unitholders might change, and Unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
Transfers of Units to Employees or Directors of Pengrowth Corporation and Pengrowth Management.Under Pengrowth’s trust unit option plan and the share appreciation rights plan, employees and directors of Pengrowth Corporation and Pengrowth Management may receive trust units for less than their fair market value on the date of issuance. The United States federal income tax treatment of such transfers to the Registrant and the Unitholders is not clear. It is possible that the IRS could take the position that the Registrant should be treated as having disposed of a pro rata portion of all of its assets, equal in value to the amount of such discount, thereby recognizing taxable gain (or loss), which would flow through to Unitholders. In such event, the Registrant may be entitled to an offsetting compensation deduction.
Disposition of Trust Units
Recognition of Gain or Loss.Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss of a maximum rate of 15%. A portion of any gain or loss on a sale or exchange of trust units (which portion could be substantial) will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to the recapture of depletion or depreciation deductions. Ordinary income attributable to depletion deductions and depreciation recapture could exceed net taxable gain realized upon the sale of the trust units and may be recognized even if there is a net taxable loss realized on the sale of the trust units. Thus, a unitholder may recognize both ordinary income and a capital loss upon a taxable disposition of trust units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income in the case of individuals and may only be used to offset capital gain in the case of corporations.
The IRS has ruled that a person who acquires interests in an entity such as the Registrant, which is treated as a partnership for United States federal income tax purposes, in separate transactions must maintain a single, combined adjusted tax basis for the interests. Upon a sale or
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other disposition of less than all of those interests, a portion of that tax basis must be ratably allocated to the interests sold using an “equitable apportionment” method. Treasury regulations allow a seller of such an interest who can identify the interest sold with an ascertainable holding period to elect to use that holding period. Thus, according to the ruling, a unitholder will be unable to select high or low basis trust units to sell as would be the case with corporate stock but, according to the regulations, may designate trust units sold for purposes of determining the holding period of the trust units sold. A unitholder electing to use the actual holding period of trust units sold must consistently use that approach for all subsequent sales and exchanges of trust units. A unitholder considering the purchase of additional trust units or the sale of trust units purchased in separate transactions should consult his own tax advisor regarding the application of this ruling and the recently finalized regulations.
Allocations Between Transferors and Transferees.In general, the Registrant’s taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the Unitholders in proportion to the number of trust units owned by each of them on the first business day of the month (the “allocation date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business, and other extraordinary items, will be allocated among the Unitholders on the allocation date in the month in which that gain or loss is recognized.
Notification Requirements.A unitholder who sells or exchanges trust units is required to notify the Registrant in writing of that sale or exchange within 30 days after the sale or exchange. The Registrant is required to notify the IRS of that transaction and to furnish certain information to the transferor and transferee. However, these reporting requirements do not apply with respect to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Additionally, a transferor and a transferee of trust units will be required to furnish statements to the IRS, filed with its income tax return for the taxable year in which the sale or exchange occurred, that allocates the consideration paid for the trust units. This information will be provided by the Registrant. Failure to satisfy these reporting obligations may lead to the imposition of substantial penalties.
Constructive Termination.The Registrant will be considered to have been terminated for United States federal income tax purposes if there is a sale or exchange of 50% or more of the total trust units within a 12-month period. A termination of the Registrant will result in a decrease in tax depreciation available to the Unitholders in the year of termination and in the closing of its taxable year for all Unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of the Registrant’s taxable year may result in more than 12 months’ taxable income or loss of the Registrant being includable in his taxable income for the year of termination. New tax elections would have to be made by the Registrant subsequent to a termination, including a new election under Section 754 of the Code. Adverse tax consequences could ensue if the Registrant were unable to determine that the termination had occurred. Finally, a termination of the Registrant could result in taxation of the Registrant as a corporation if the qualifying income exception was not met in the short taxable years caused by termination. See “Classification of the Registrant as a Partnership.”
Treatment of Trust Unit Lending and Short Sales.A unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed
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of ownership of those trust units. If so, he would no longer be a partner with respect to those trust units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period, any the Registrant income, gain, deduction or loss with respect to those trust units would not be reportable by the unitholder, any cash distributions received by the unitholder with respect to those trust units would be fully taxable and all of such distributions would appear to be treated as ordinary income. Unitholders desiring to assure their status as owners of trust units and avoid the risk of gain recognition resulting from the application of these rules should modify any applicable brokerage account agreements to prohibit their brokers from borrowing or loaning their trust units.
The Code also contains provisions affecting the taxation of some financial products and securities, including interests in entities such as the Registrant, by treating a taxpayer as having sold an “appreciated” interest, one in which gain would be recognized if it were sold, assigned or otherwise terminated at its fair market value, if the taxpayer or related persons enter into a short sale, an offsetting notional principal contract, or a futures or forward contract with respect to the interest on substantially identical property. Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the interest or substantially identical property. The Secretary of Treasury is authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
Uniformity of Trust Units
Because the Registrant cannot match transferors and transferees of trust units, it must maintain uniformity of the economic and tax characteristics of the trust units to a purchaser of these trust units. In the absence of uniformity, the Registrant may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory.
A lack of uniformity can result from a literal application of some Treasury regulations. Any non-uniformity could have a negative impact on the value of the trust units.
Tax-Exempt Organizations and Regulated Investment Companies
Employee benefit plans (including individual retirement accounts (“IRAs”) and other retirement plans) and most other organizations exempt from federal income tax (each, a “TEO”) are subject to federal income tax on unrelated business taxable income (“UBTI”). Because we expect substantially all income of the Registrant to be royalty income, rents from real property or interest, none of which is UBTI, a TEO should not be taxable on any income generated by ownership of the trust units except as described in the next paragraph. However, the royalty indenture between Pengrowth Corporation and Computershare, as trustee, is in several respects an unusual royalty indenture, for which there is no clear United States income tax guidance. It is possible that the IRS could contend that some or all of the income of the Registrant under the royalty indenture does not qualify as royalty income, but should instead be treated as UBTI. In addition, the classification of certain facilities owned by the Registrant as real property or personal property is a determination subject to uncertainty. If such facilities were determined to
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be personal property for United States federal income tax purposes, the rent derived therefrom would be UBTI to a TEO. Prospective purchasers of trust units that are TEOs are encouraged to consult their tax advisors regarding the foregoing.
If the trust units constitute “debt-financed property” within the meaning of Code Section 514(b), then a portion of any interest, rents from real property and royalty income received by the TEO attributable to the trust units will be treated as UBTI and thus will be taxable to a TEO. Under Code Section 514(b), “debt-financed property” is defined as any property which is held to produce income and with respect to which there is acquisition indebtedness.
A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends, gains from the sale of stocks or securities or foreign currency or certain related sources (“RIC qualifying income”). It is anticipated that substantially all of the Registrant’s gross income will be non-RIC qualifying income. Furthermore, it is unclear whether gain from the sale of the trust units is properly treated as RIC qualifying income. Prospective purchasers of our trust units that are regulated investment companies are encouraged to consult their tax advisors regarding the impact of these rules on their status as regulated investment companies.
Administrative Matters
Information Returns.The Registrant currently is not required to file a United States federal income tax return, since it has no gross income derived from sources within the United States or gross income which is effectively connected with the conduct of a trade or business within the United States. However, the IRS may require a unitholder to provide statements or other information necessary for the IRS to verify the accuracy of the reporting by the unitholder on its income tax return of any items of the Registrant’s income, gain, loss, deduction, or credit. If the Registrant were to file a United States tax return in future tax years, the filing would change the manner in which they provide tax information to the Unitholders and special procedures would also apply to an audit of such tax return by the IRS.
Registration as a Tax Shelter.The Code requires that “tax shelters” be registered with the Secretary of the Treasury. It is arguable that the Registrant is not subject to the registration requirement on the basis that it will not constitute a tax shelter. However, the Registrant has registered as a tax shelter with the Secretary of the Treasury because of the absence of assurance that it will not be subject to tax shelter registration and in light of the substantial penalties which otherwise might be imposed if it failed to register and it were subsequently determined that registration was required.
The IRS has issued the Registrant the following tax shelter registration number: 99068000003.
You must report this registration number to the IRS, if you claim any deduction, loss, credit, or other tax benefit or report any income by reason of your investment in the Registrant.
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You must report the registration number (as well as the name, and taxpayer identification number of the Registrant) on Internal Revenue Service Form 8271. The Registrant’s taxpayer identification number is 98-0185056.
Internal Revenue Service Form 8271 must be attached to the return on which you claim the deduction, loss, credit, or other tax benefit or report any income.
Issuance of a registration number does not indicate that an investment in the Registrant or the claimed tax benefits have been reviewed, examined, or approved by the IRS.
A unitholder who sells or otherwise transfers trust units must furnish the tax shelter registration number to the transferee. The penalty for failure of the transferor of a trust unit to furnish the registration number to the transferee is $100 for each such failure. The Unitholders must disclose the tax shelter registration number of the Registrant on Internal Revenue Service Form 8271 to be attached to the tax return on which any deduction, loss or other benefit generated by the Registrant is claimed or income of the Registrant is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed herein are not deductible for federal income tax purposes.
Accuracy-Related Penalties.A penalty equal to 20% of the amount of any portion of an underpayment of tax which is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, with respect to any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith with respect to that portion. Special rules exist for “tax shelters,” a term that in this context does not appear to include the Registrant. When necessary, the Registrant will make a reasonable effort to furnish sufficient information for Unitholders to make adequate disclosure on their returns to avoid any penalty attributable to ownership of the trust units.
Foreign Partnership Reporting.A unitholder who contributes more than U.S. $100,000 to the Registrant (when added to the value of any other property contributed to the Registrant by such person or a related person during the previous 12 months) in exchange for trust units, may be required to file Internal Revenue Service Form 8865,Return of US Persons With Respect to Certain Foreign Partnerships, in the year of the contribution. There may be other circumstances when a unitholder is required to file Internal Revenue Service Form 8865. See “Tax Consequences of the Reorganization of Trust Unit Capital”.
ERISA CONSIDERATIONS
An investment in trust units by employee benefit plans is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions ofThe Employee Retirement Income Security Act of 1974(United States) (“ERISA”) and restrictions imposed by Section 4975 of the Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension,
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profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Prior to an employee benefit plan investing in trust units, consideration should be given to, among other things to: (a) whether the investment is prudent under Section 404(a)(1)(B) of ERISA; (b) whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and (c) whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in trust units is authorized by the appropriate plan documents and is a proper investment for the plan. Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the plan. In addition to considering whether the purchase of trust units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in trust units, be deemed to own an undivided interest in the assets of the Registrant, with the result that Pengrowth Management also would be a fiduciary of the plan and the Registrants’ operations would be subject to the regulatory provisions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code.
Regulations issued by the U.S. Department of Labor provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things, the equity interests acquired by employee benefit plans are (i) publicly offered securities; i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other; (ii) freely transferable; and (iii) registered under some provisions of the federal securities laws. the Registrant’s assets should not be considered “plan assets” under these regulations because our trust units will satisfy the requirements described above. Plan fiduciaries contemplating a purchase of our trust units should consult with their own counsel regarding the consequences under ERISA and the Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, and the tax issues discussed above.
NOTICES PURSUANT TO REGULATION BTR
None.
IDENTIFICATION OF THE AUDIT COMMITTEE
The Registrant has a separately-designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Thomas A. Cumming, Michael A. Grandin and Michael S. Parrett.
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AUDIT COMMITTEE FINANCIAL EXPERT
The board of directors of the Registrant has determined that Messrs. Michael A. Grandin and Michael S. Parrett, members of the Registrant’s audit committee, qualify as an audit committee financial experts for purposes of paragraph (8) of General Instruction B to Form 40-F. The board of directors has further determined that Messrs. Grandin and Parrett are also independent, as that term is defined in the Corporate Governance Listing Standards of the New York Stock Exchange. The Commission has indicated that the designation of Messrs. Grandin and Parrett as audit committee financial experts does not make them an “expert” for any purpose, impose any duties, obligations or liabilities on them that are greater than those imposed on members of the audit committee and the board of directors who do not carry this designation or affect the duties, obligations or liabilities of any other member of the audit committee or the board of directors.
GOVERNANCE DISCLOSURE INCORPORATED BY REFERENCE
Certain disclosure regarding the corporate governance practices of the Registrant, including disclosure of the Registrant’s code of ethics, principal accountant fees and services, pre-approval policies and procedures, off-balance sheet arrangements and contractual obligations, is included on pages 55 through 57 of the Annual Information Form contained in Appendix A and incorporated herein.
UNDERTAKING
Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.
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SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Form to be signed on its behalf by the undersigned, thereunto duly authorized.
| Date: July 13, 2004 | PENGROWTH ENERGY TRUST by its Administrator PENGROWTH CORPORATION | |||
| By: | /s/ James S. Kinnear | |||
| James S. Kinnear | ||||
| President and Chief Executive Officer | ||||
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APPENDIX A
PENGROWTH ENERGY TRUST RENEWAL ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2003
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PENGROWTH ENERGY TRUST
RENEWAL ANNUAL INFORMATION FORM
Pengrowth Energy Trust is an energy investment trust formed under the laws of
the Province of Alberta which offers and sells its trust units to the public.
The trust units are not “deposits” within the meaning of the Canadian Deposit
Insurance Corporation Act (Canada) and are not insured under the provisions of
that Act or any other legislation. Furthermore, Pengrowth Energy Trust is not
a trust company and, accordingly, is not registered under any trust and loan
company legislation as it does not carry on or intend to carry on the business
of a trust company.
May 17, 2004
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TABLE OF CONTENTS
| GLOSSARY OF TERMS AND ABBREVIATIONS | 4 | |||
| CONVERSION | 5 | |||
| PRESENTATION OF OUR FINANCIAL INFORMATION | 5 | |||
| PRESENTATION OF OUR RESERVE INFORMATION | 6 | |||
| FORWARD-LOOKING STATEMENTS | 6 | |||
| PENGROWTH ENERGY TRUST | 8 | |||
| GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST | 8 | |||
| Organization and Structure | 8 | |||
| Business Strategy and Strengths | 9 | |||
| Historical Development | 10 | |||
| Recent Acquisitions, Financings and Developments | 12 | |||
| Trends | 16 | |||
| PENGROWTH MANAGEMENT LIMITED | 16 | |||
| Business | 16 | |||
| Management Agreement | 16 | |||
| PENGROWTH CORPORATION — OPERATIONAL INFORMATION | 18 | |||
| Principal Properties | 18 | |||
| Reserves | 24 | |||
| Additional Information Relating to Reserves Data | 32 | |||
| Other Oil And Gas Information | 33 | |||
| Production | 35 | |||
| Replacement of Properties | 37 | |||
| Borrowing | 37 | |||
| TRUST UNITS | 37 | |||
| The Trust Indenture | 37 | |||
| The Trustee | 38 | |||
| Redemption Right | 38 | |||
| Voting at Meetings of Pengrowth Trust | 38 | |||
| Voting at Meetings of Pengrowth Corporation | 38 | |||
| Termination of Pengrowth Trust | 39 | |||
| Unitholder Limited Liability | 39 | |||
| Special Voting Unit | 39 | |||
| 2004 Annual and Special Meeting | 39 | |||
| THE ROYALTY INDENTURE | 39 | |||
| Royalty Units | 39 | |||
| The Royalty | 40 | |||
| The Trustee | 41 | |||
| DISTRIBUTIONS | 41 | |||
| INDUSTRY CONDITIONS | 41 | |||
| Government Regulation | 41 | |||
| Pricing and Marketing — Oil | 42 | |||
| Pricing and Marketing — Natural Gas | 42 | |||
| The North American Free Trade Agreement | 42 | |||
| Provincial Royalties and Incentives | 42 | |||
| Environmental Regulation | 44 |
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| SELECTED FINANCIAL INFORMATION | 44 | |||
| MANAGEMENT’S DISCUSSION AND ANALYSIS OF OPERATING RESULTS AND FINANCIAL CONDITION | 45 | |||
| MARKET FOR SECURITIES | 45 | |||
| DIRECTORS AND OFFICERS | 45 | |||
| Directors and Officers of Pengrowth Management | 45 | |||
| Principal Holders of Shares of Pengrowth Management | 45 | |||
| Directors and Officers of Pengrowth Corporation | 46 | |||
| RISK FACTORS | 47 | |||
| CONFLICTS OF INTEREST | 55 | |||
| CODE OF ETHICS | 56 | |||
| PRINCIPAL ACCOUNTANT FEES AND SERVICES | 56 | |||
| PRE-APPROVAL POLICIES AND PROCEDURES | 57 | |||
| OFF-BALANCE SHEET ARRANGEMENTS | 57 | |||
| TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS | 57 | |||
| DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE | 57 | |||
| ADDITIONAL INFORMATION | 57 |
Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2003.
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GLOSSARY OF TERMS AND ABBREVIATIONS
Capitalized terms in this Annual Information Form has the meanings set forth below:
Corporate
| • | Board of Directorsrefers to the board of directors of Pengrowth Corporation; |
| • | Computersharerefers to Computershare Trust Company of Canada; |
| • | Pengrowth, we, us and ourrefers to Pengrowth Trust and Pengrowth Corporation on a consolidated basis; |
| • | Pengrowth Corporationrefers to Pengrowth Corporation, the administrator of Pengrowth Trust; |
| • | Pengrowth Managementrefers to Pengrowth Management Limited, the manager of Pengrowth Trust and Pengrowth Corporation; |
| • | Pengrowth Trustrefers to Pengrowth Energy Trust; and |
| • | unitholdersrefers to holders of trust units issued by Pengrowth Trust. |
Engineering
| • | Developed Non-Producing Reservesrefers to those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown; |
| • | Developed Producing Reservesrefers to those reserves expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production and the date of resumption of production must be known with reasonable certainty; |
| • | Developed Reservesrefers to those reserves that are expected to be recovered from existing wells and facilities or, if facilities have not been installed, that would involve a low expenditure to put the reserves on production. The developed category may be subdivided into producing and non-producing; |
| • | Emerarefers to Emera Inc. and its subsidiaries, associates and affiliates on a consolidated basis; |
| • | GLJrefers to Gilbert Laustsen Jung Associates Ltd., independent petroleum consultants, Calgary, Alberta; |
| • | GLJ Reportrefers to the report prepared by GLJ dated February 19, 2004, having an effective date of December 31, 2003; |
| • | Grosswith respect to production and reserves refers to the total production and reserves attributable to a property before the deduction of royalties and with respect to land and wells refers to the total number of acres or wells, as the case may be, in which Pengrowth has a working interest or a royalty interest; |
| • | Netrefers to Pengrowth’s working interest share of production or reserves, as the case may be, after the deduction of royalties, and, with respect to land and wells, refers to Pengrowth’s working interest share therein; |
| • | Pengrowth Gross Reserves or Pengrowth Interest refers to Pengrowth’s working interest and royalty interest share of reserves before the deduction of royalties; |
| • | Pengrowth Total Proved Plus Probable Reservesmeans Pengrowth’s working interest share of Total Proved Plus Probable Reserves before the deduction of royalties; |
| • | Probable Reservesrefers to those additional reserves that are less likely to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves; |
| • | Proved Reservesrefers to those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves; |
| • | Reserve Life Indexrefers to the number of years determined by dividing the aggregate of the reserves of a property by the estimated production per year from such property using estimated production for the year 2004 as a reference; |
| • | Reservesrefers to estimated remaining quantities of oil and natural gas and related substances anticipated to be recovered from known accumulations, from a given date forward, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and specified economic conditions which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimate; |
| • | royalty interestrefers to an interest in an oil and gas property consisting of a royalty granted in respect of production from the property; |
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| • | Total Proved Plus Probable Reservesmeans the aggregate of Proved Reserves and Probable Reserves before the deduction of royalties; |
| • | Undeveloped Reservesrefers to those reserves expected to be produced from known accumulation where a significant expenditure (eg. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserve classification (proved, probable) to which they are assigned; |
| • | Unitizationrefers to a process whereby owners of adjoining properties pool reserves into a single unit operated by one of the owners, typically in order to conduct secondary recovery projects in a manner that promotes improved recovery of reserves from a pool or field; and |
| • | working interestrefers to the percentage of undivided interest held by Pengrowth in an oil and gas property. |
Abbreviations
| • | bbl, bbls, mbbls, and mmbblsrefers to barrel, barrels, thousands of barrels and millions of barrels, respectively; |
| • | bblpdrefers to barrels per day; |
| • | boe, mboe and mmboerefers to barrels of oil equivalent, thousands of barrels of oil equivalent and millions of barrels of oil equivalent, respectively, on the basis of one boe being equal to one barrel of oil or NGLs or six mcf of natural gas; barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of 6 mcf of natural gas to one boe is based on an energy equivalency conversation method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead; |
| • | boepdrefers to barrels of oil equivalent per day; |
| • | $M and $MMrefers to thousands of dollars and millions of dollars, respectively; |
| • | mmbtu and mmbtupdrefers to a million british thermal units and million british thermal units per day respectively; |
| • | mcf, mmcf, bcf and tcfrefers to thousands of cubic feet, millions of cubic feet, billions of cubic feet and trillions of cubic feet, respectively; |
| • | mcfpd and mmcfpdrefers to thousands of cubic feet per day and millions of cubic feet per day respectively; and |
| • | NGLsrefers to natural gas liquids. |
CONVERSION
In this Annual Information Form measurements are given in Standard Imperial or metric units only. The following table sets forth certain standard conversions.
| To Convert From | To | Multiply By | ||||
| mcf | cubic metre | 28.174 | ||||
| cubic metre | cubic feet | 35.494 | ||||
| bbls | cubic metre | 0.159 | ||||
| cubic metre | bbls | 6.290 | ||||
| feet | metre | 0.305 | ||||
| metre | feet | 3.281 | ||||
| miles | kilometre | 1.609 | ||||
| kilometre | miles | 0.621 | ||||
| acres | hectares | 0.405 | ||||
| hectares | acres | 2.471 | ||||
Unless otherwise stated, all sums of money referred to in this Annual Information Form are expressed in Canadian dollars.
PRESENTATION OF OUR FINANCIAL INFORMATION
Unless we indicate otherwise, financial information in this Annual Information Form has been prepared in accordance with generally accepted accounting principles (“GAAP”) in Canada. Canadian GAAP differs in some significant respects from U.S. GAAP and thus our financial statements may not be comparable to the financial statements
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of U.S. companies. The principal differences as they apply to us are summarized in note 20 to the audited annual consolidated financial statements of Pengrowth Trust beginning on page 91 of Pengrowth Trust’s 2003 Annual Report.
We present our financial information in Canadian dollars.
PRESENTATION OF OUR RESERVE INFORMATION
The United States Securities and Exchange Commission (the “SEC”) generally permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and interests of others which are those reserves that a company has demonstrated by actual production or conclusive formation tests to be economically producible under existing economic and operating conditions. In 2003, the securities regulatory authorities in Canada (other than Québec) adopted National Instrument 51-101 —Standards of Disclosure for Oil and Gas Activities(“NI 51-101”), which imposes new oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves but also probable reserves, and to disclose reserves and production on a gross basis before deducting royalties. Probable reserves are of a higher risk and are less likely to be accurately estimated or recovered than proved reserves. Because we are permitted to prepare this Annual Information Form in accordance with Canadian disclosure requirements, we have disclosed in this Annual Information Form and in the documents incorporated by reference reserves designated as “probable”. If this Annual Information Form was required to be prepared in accordance with U.S. disclosure requirements, the SEC’s guidelines would prohibit reserves in these categories from being included. Moreover, in accordance with Canadian practice, we have determined and disclosed estimated future net cash flow from our reserves using both escalated and constant prices and costs; for the constant prices and costs case, prices and costs in effect as of December 31, 2003 were held constant for the economic life of the reserves. The SEC does not permit the disclosure of estimated future net cash flow from reserves based on escalating prices and costs and generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. For a description of these and additional differences between Canadian and U.S. standards of reporting reserves, see “Risk Factors — Canadian and United States practices differ in reporting reserves and production”. Additional information prepared in accordance with United States Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities” relating to our oil and gas reserves is set forth in our Form 40-F.
FORWARD-LOOKING STATEMENTS
Certain statements contained in this Annual Information Form, including certain documents incorporated by reference, constitute forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in our forward-looking statements. We believe the expectations reflected in those forward-looking statements are reasonable. However, we cannot assure you that these expectations will prove to be correct. You should not unduly rely on forward-looking statements included, or incorporated by reference, in this Annual Information Form. These statements speak only as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference in this Annual Information Form, as the case may be.
In particular, this Annual Information Form, including the documents incorporated by reference, contains forward-looking statements pertaining to the following:
| • | the size of our reserves; |
| • | estimates of future oil and natural gas production; |
| • | projections of market prices and costs; |
| • | supply and demand for oil and natural gas; |
| • | expectations regarding the ability to raise capital and to continually add to our reserves through acquisitions and exploration and development; and |
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| • | treatment under governmental regulatory regimes. |
Our actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this Annual Information Form, including under “Risk Factors”:
| • | volatility in market prices for oil and natural gas; |
| • | liabilities inherent in our oil and gas operations; |
| • | uncertainties associated with estimating reserves; |
| • | competition for, among other things, capital, reserves, undeveloped lands and skilled personnel; |
| • | incorrect assessments of the value of our acquisitions; and |
| • | geological, technical, drilling and processing problems. |
These factors should not be construed as exhaustive. We undertake no obligation to publicly update or revise any forward-looking statements.
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PENGROWTH ENERGY TRUST
Pengrowth Trust is an oil and gas royalty trust that was created under the laws of the Province of Alberta on December 2, 1988. Pengrowth Trust is governed by a trust indenture dated June 17, 2003 (amending and restating the trust indenture dated April 23, 2002), with further amendments authorized by unitholders on April 22, 2004, between Pengrowth Corporation and Computershare, as trustee. In 1996, Pengrowth Trust’s original name, “Pengrowth Gas Income Fund”, was changed to “Pengrowth Energy Trust”. The purpose of Pengrowth Trust is to purchase and hold royalty units issued by Pengrowth Corporation, its majority owned subsidiary, and to issue trust units to members of the public. Pengrowth Corporation acquires, owns and manages working interests and royalty interests in oil and natural gas properties. The beneficiaries of Pengrowth Trust are the unitholders.
Pengrowth Corporation was created under the laws of the Province of Alberta on December 30, 1987. In 1998, the name of Pengrowth Corporation was changed from “Pengrowth Gas Corporation” to “Pengrowth Corporation”. Pengrowth Corporation has 1,100 common shares outstanding, 1,000 of which are owned by Pengrowth Trust and 100 of which are owned by Pengrowth Management.
Pengrowth Management was created under the laws of the Province of Alberta on December 16, 1982. Pengrowth Management serves as the manager of Pengrowth Trust and as the manager of Pengrowth Corporation.
GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST
Organization and Structure
Under a royalty indenture dated June 17, 2003 (amending and restating the royalty indenture dated April 23, 2002), with further amendments authorized by unitholders on April 22, 2004, between Pengrowth Corporation and Computershare, as trustee, Pengrowth Corporation has granted a royalty consisting of a 99% share of “royalty income” to the holders of royalty units. The royalty units represent fractional undivided interests in the royalty.
Under the trust indenture, Pengrowth Trust has issued trust units to the unitholders. Each trust unit represents a fractional undivided beneficial interest in Pengrowth Trust. Our unitholders are entitled to receive monthly distributions in respect of the royalty and in respect of investments that are held directly by us.
Pengrowth Trust presently holds approximately 99.9% of the royalty units issued by Pengrowth Corporation. In addition, Pengrowth Trust holds other permitted investments, such as oil and gas processing facilities and cash.
Pursuant to the unanimous shareholder agreement dated June 17, 2003 (amending and restating the unanimous shareholder agreement dated April 23, 2002), with further amendments authorized by unitholders on April 22, 2004, among Pengrowth Management, Pengrowth Trust, Pengrowth Corporation and Computershare, our unitholders and holders of royalty units (other than Computershare) are entitled to notice of, and to attend, all meetings of shareholders of Pengrowth Corporation and vote as shareholders at all meetings of the shareholders of Pengrowth Corporation to the same extent as if they were holders of common shares of Pengrowth Corporation, including voting on the election of the directors of Pengrowth Corporation (other than the two directors to be appointed by Pengrowth Management), approving its financial statements, appointing its auditors and appointing the auditor of Pengrowth Trust. In addition, our unitholders are entitled to vote on any proposed amendment to the unanimous shareholder agreement.
The principal business of Pengrowth Management is that of a specialty fund manager. Pengrowth Management currently provides advisory, management, and administrative services to Pengrowth Trust and to Pengrowth Corporation. In particular, Pengrowth Management also manages and provides services relating to the acquisition and disposition of oil and natural gas properties and other related assets on behalf of Pengrowth Corporation.
James S. Kinnear, President and a director of Pengrowth Management and Chairman, President, Chief Executive Officer and a director of Pengrowth Corporation, owns, directly or indirectly, all of the issued and outstanding voting securities of Pengrowth Management.
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The following chart illustrates the organization and structure of Pengrowth.
Business Strategy and Strengths
Our goal is to maximize cash distributions on a per trust unit basis to our unitholders over time while enhancing the value of our trust units. We generally do not explore for oil and natural gas. Instead, we focus on making accretive acquisitions and maximizing the value of our mature property base by reducing operating costs, implementing new development technologies, including three dimensional seismic and tertiary recovery operations, and implementing other operational efficiencies.
Our ability to pay out distributions while enhancing unitholder value over time is dependent upon effective operations and our ability to make acquisitions which yield returns that exceed our cost of capital. We evaluate acquisition opportunities based upon the following acquisition criteria:
Financial
| • | Acquisitions should increase future distributions on a per trust unit basis based upon current economics. |
| • | The undiscounted aggregate projected future net cash flow from the properties should exceed the aggregate purchase price of the properties and provide a reasonable rate of return. |
| • | The oil and gas producing properties to be acquired should, in the context of the market, have an attractive rate of return and a relatively low reserve cost. |
Operational
| • | Properties to be acquired should be high quality, relatively long life, proven producing properties. Pengrowth Corporation gives priority to properties with: |
| • | low anticipated capital expenditures relative to the cash generation potential of the properties; | |||
| • | relatively low operating costs or high netbacks; | |||
| • | experienced, well regarded industry operators or where operatorship may be assumed by Pengrowth; | |||
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| • | favourable production history; |
| • | upside potential through infill drilling, improved field operations and other development activities; |
| • | relatively long reserve life; and | |||
| • | low environmental and site remediation risk. | |||
Independent Verification
| • | Each purchase of new properties will be based on an independent engineering report except for properties where the purchase price is less than $5 million. |
Our structure, tax effectiveness and cost of capital allow us to bid competitively for oil and natural gas properties relative to taxable corporations and other taxable entities. Opportunities to acquire oil and gas properties generally arise from sellers looking to reduce indebtedness, seeking funds for higher risk exploration and development activities, exiting the business, or fulfilling other strategic objectives.
Historical Development
Pengrowth Corporation’s first acquisition, in December of 1988, was the purchase of a 2.6507% interest in the Dunvegan Gas Unit No. 1 located near Fairview, Alberta in the Peace River Arch. Pengrowth Corporation financed the acquisition by issuing 1,250,000 royalty units at a price of $10.00 per royalty unit, substantially all of which were issued to Pengrowth Trust. Pengrowth Trust issued 1,243,500 trust units to the public at a price of $10.00 per trust unit for gross proceeds of $12,435,000 which were used to pay for the royalty units. An additional 56,500 royalty units were also issued in the public offering which remain outstanding.
Commencing in 1991, Pengrowth Management adopted a plan, and established criteria, to build unitholder value through accretive acquisitions and financings of those acquisitions. Thereafter Pengrowth Corporation completed a series of acquisitions that were financed through periodic issuances of trust units, rights offerings and bank indebtedness.
Pengrowth Trust commenced a series of fully marketed equity offerings in 1994 to fund various property acquisitions. Since that time Pengrowth Corporation has continued a course of targeted asset acquisitions for cash. The most significant purchases and financings are described below.
Effective July 1, 1997, Pengrowth Corporation acquired a 98.11% working interest in the Judy Creek Beaverhill Lake Unit, a 94.58% working interest in the Judy Creek West Beaverhill Lake Unit, and a 9.58% working interest in the Swan Hills Unit No. 1 for a net purchase price of $496.1 million. In November 1997, Pengrowth Corporation increased its working interest in the Judy Creek Beaverhill Lake Unit to 100%. On October 15, 1997, Pengrowth Trust completed an offering of 23,928,572 trust units on an installment receipt basis with $12.50 per trust unit paid on closing and the balance of $8.75 per unit due on or before October 15, 1998. Gross proceeds raised amounted to $508 million comprised of cash of $299 million and an installment receivable of $209 million. On April 15, 1998, Pengrowth Corporation assumed operatorship of the Judy Creek Units from Imperial Oil Resources Ltd. Effective October 15, 1998, Pengrowth Trust acquired certain facilities interests related to operations in the Judy Creek and Swan Hills areas from Pengrowth Corporation for consideration of $106,000,000. Pengrowth Trust entered into an agreement to lease the facilities back to Pengrowth Corporation.
On November 10, 2000, Pengrowth Trust issued 8,165,000 trust units to raise gross proceeds of $155,135,000 which were applied to acquire interests in Goose River, House Mountain, Minnehik Buck Lake, Mitsue and Weyburn from Canadian Natural Resources Limited for cash consideration of $128,000,000 and the transfer of certain properties.
On May 31, 2001, Pengrowth Trust issued 10,895,000 trust units to raise gross proceeds of $225,526,500.
Effective June 15, 2001, Pengrowth Corporation acquired a royalty representing substantially all of the beneficial interest in the natural gas and liquids production from an 8.4% working interest in the Sable Offshore Energy Project (“SOEP”) from Nova Scotia Resources (Ventures) Limited (“NSRVL”), for $265 million (net adjusted price of $228.4 million). On December 24, 2001, Pengrowth Corporation acquired certain additional petroleum and natural gas rights and other assets from NSRVL for a gross purchase price of $27.5 million.
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On June 4, 2002, Pengrowth Trust issued 8,000,000 trust units at a price of $15.40 per trust unit for total gross proceeds of $123.2 million.
On October 1, 2002, with an effective date of July 1, 2002, Pengrowth Corporation acquired certain properties located in northern British Columbia from Calpine Natural Gas Partnership for net consideration after adjustments of $352 million.
In November, 2002, Pengrowth Trust completed a cross-border equity offering in Canada and the United States of 20,125,000 trust units at $14.00 per trust unit (US$8.93 per unit) for gross proceeds of approximately $281.8 million. In total, two public trust unit offerings completed during 2002 raised $380 million in net equity proceeds.
On April 23, 2003, Pengrowth completed a US$200 million private placement of senior unsecured notes to a group of U.S. investors. The notes were offered in two tranches: US$150 million at 4.93% due April 23, 2010 and US$50 million at 5.47% due April 23, 2013. Interest on the notes is payable semi-annually.
On May 7, 2003, Pengrowth Corporation acquired an 8.4% working interest in the four SOEP production facilities downstream of Thebaud Central Platform from SOEP co-venturers ExxonMobil Canada Properties, Shell Canada Resources Limited, Imperial Oil Resources Ltd. and Mosbacher Operating Company Ltd. for net consideration of approximately $57 million.
Since the formation of Pengrowth in 1988, Pengrowth has completed a total of 17 public financings of equity for gross proceeds in excess of $2 billion.
Recent Acquisitions, Financings and Developments
SOEP Facilities Acquisition
On December 31, 2003, Pengrowth Corporation acquired an 8.4% working interest in the SOEP offshore production platforms and associated sub-sea field gathering lines from Emera for net consideration of approximately $65 million including approximately $20 million in cash and a $45 million note payable over three years. In addition, Pengrowth Corporation obtained an 8.4% working interest in the SOEP reserves in exchange for its 99.9% SOEP royalty interest in 8.4% of the reserves and production from SOEP. Combined with Pengrowth Corporation’s May, 2003 purchase of an 8.4% working interest in the downstream SOEP pipelines and processing facilities, Pengrowth Corporation holds an undivided 8.4% working interest in all of SOEP. In addition, in June, 2003, Pengrowth acquired interests in eleven significant discovery licenses from Nova Scotia Resources (Ventures) Limited for $4.5 million and a 10% net profits interest.
2004 Equity Financing
On March 23, 2004, Pengrowth Trust completed an equity offering of 10,900,000 trust units, including 2,700,000 trust units issued upon exercise of an underwriters’ option, at a price of $18.40 per trust unit for gross proceeds of $200.5 million.
Murphy Oil Acquisition
On April 8, 2004 Pengrowth Corporation entered into an agreement with a subsidiary of Murphy Oil Corporation to acquire oil and natural gas assets in Alberta and Saskatchewan for $550 million through the purchase of shares in a Alberta numbered company.
The properties to be acquired represent a diverse group of assets within western Canada, including interests in the West Central and Peace River Arch areas (including interests in the McLeod, Deep Basin and Peace River Arch areas); Southern Alberta (including interests in the Countess, Princess and Twining/Three Hills areas); and heavy oil (including interests in the Lindbergh, Tangleflags, and Lloydminster areas). Current production from the interests Pengrowth is acquiring is approximately 15,500 boepd before royalties, comprised of 46 mmcfpd of natural gas, 1,550 bblpd of light medium crude oil and natural gas liquids and 6,250 bblpd of heavy oil. Subsequent to the acquisition, Pengrowth Corporation’s total production will increase from the current level of approximately 45,600 boepd to approximately 60,000 boepd, an increase of 32%. The properties also include 219,000 acres of undeveloped land.
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Pengrowth Corporation will complete the acquisition with cash on hand including the proceeds of the March 23, 2004 equity issue and through committed interim debt provided by Pengrowth Corporation’s lead banker. Various options are being examined with respect to permanent financing. There are limited tax pools associated with the transaction and Pengrowth Corporation will assume various marketing and transportation arrangements as part of the consideration.
2004 Annual and Special Meetings
Reclassification of Trust Unit Capital
At the annual general and special meeting of the shareholders of Pengrowth Corporation, the annual and special meeting of unitholders and the special meeting of royalty unitholders, held on April 22, 2004, amendments were approved to the trust indenture, royalty indenture, unanimous shareholder agreement and articles of Pengrowth Corporation to facilitate the reclassification of our trust unit capital by in excess of 95% of the votes cast at the meetings.
The unitholders approved the reclassification of our trust unit capital into two classes of units: Class A Trust Units and Class B Trust Units (the “A/B Unit Structure”). Each class of new trust units will have the same rights as the existing trust units to vote, obtain distributions and obtain assets upon the wind-up or dissolution of Pengrowth Trust. The only distinction between the two classes of units will be in respect of the residency of the persons entitled to hold and trade the Class A and Class B Trust Units. The Class A Trust Units are not subject to any residency restriction, will trade on both the TSX and NYSE, may be exchanged at any time for Class B Trust Units provided that the holder is a resident of Canada and provides suitable residency declaration, and are subject to a restriction on the number to be issued such that the Class A Trust Units will not exceed 99% (the “Ownership Threshold”) of the number of issued and outstanding Class B Trust Units (subject to certain transitional provisions). The Class B Trust Units may not be held by non-residents of Canada, will trade only on the TSX and may be exchanged by holder for Class A Trust Units, provided that the Ownership Threshold will not be exceeded.
Pengrowth Trust intends to take all necessary measures to ensure that it continues to qualify as a mutual fund trust, within the meaning of theIncome Tax Act(Canada) (the “Tax Act”), on the basis that it is not reasonable, at any time, to consider that Pengrowth Trust was established or is maintained primarily for the benefit of non-residents of Canada.
Pengrowth Trust was formed in 1988 as a “mutual fund trust” under the Tax Act. The trust units are listed and posted for trading on the New York Stock Exchange (“NYSE”) under the symbol PGH and on the Toronto Stock Exchange (“TSX”) under the symbol PGF.UN. Since the trust units were listed on the NYSE in April, 2002, and in particular since the completion of the cross-border offering of trust units in November, 2002, Pengrowth Trust has experienced increased interest in its trust units by non-residents of Canada, both in terms of trading volumes and level of ownership.
In making residency determinations, Pengrowth Trust has relied upon ADP Reports (reports prepared by ADP Investor Communications (“ADP”) to show the geographical locations of beneficial owners of trust units) as the best available information about the residency of unitholders. There are uncertainties in the ADP Reports and Pengrowth Trust has conservatively assumed that unknown or non-reporting ADP participants represent non-resident unitholders.
On March 4, 2004, in conjunction with the release of Pengrowth Trust’s year end 2003 financial results, Pengrowth Trust announced that it was developing a strategy to address non-resident ownership levels. The following priorities were adopted by the Board of Directors:
| • | compliance with the mutual fund trust requirements of the Tax Act; |
| • | maintenance of orderly markets for trust units in Canada and the U.S.; and |
| • | the ability to continue to raise capital within Canada and the U.S. to facilitate growth of unitholder value. |
The Board of Directors have resolved, and the unitholders have approved, a resolution to amend the trust indenture to enhance the structure and procedures that regulate non-resident ownership of trust units and ensure that Pengrowth Trust continues to maintain its “mutual fund trust” status. Among other things, these amendments will result in the reclassification of the existing trust units into Class B Trust Units and the immediate conversion thereafter of any such units held by non-residents into Class A Trust Units. The Board of Directors believes that these changes together with the other changes described below are in the best interests of unitholders.
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The Board of Directors believe that the A/B Unit Structure must be put in place to maintain non-resident ownership of the equity of Pengrowth Trust at below 50%. Provisions that restrict foreign ownership are not unique. They presently exist in the transportation, banking and telecommunications sectors of the Canadian economy. The Board of Directors believe that it is practicable to maintain an active market for securities in both Canada and the United States and also maintain Pengrowth Trust’s mutual fund trust status.
The Board of Directors is of the view that:
| • | the reclassification can be accomplished without adverse tax consequences to unitholders resident either in Canada or in the United States; and |
| • | corporate mechanisms are available and will be implemented by Pengrowth Corporation to monitor and control Non-Resident ownership of Class B Units following the reclassification. |
Subject to receipt of stock exchange and other regulatory approvals, which Pengrowth Corporation has applied for, the reclassification will be implemented upon receipt of satisfactory tax advice by the Board of Directors.
Following the reclassification, the following procedures will be adopted to monitor and constrain the ownership of Class B Trust Units by non-residents of Canada:
| • | Canadian Depository for Securities Limited (“CDS”) will be advised that it is prohibited from holding Class B Trust Units on behalf of non-residents. Pengrowth Corporation will require participants in the book-based system to provide a participant declaration on a periodic basis to ensure that no non-resident of Canada owns any Class B Trust Units; |
| • | Depository Trust Company (“DTC”) will not be permitted to hold Class B Trust Units; |
| • | the number of issued and outstanding Class A Trust Units will be monitored to ensure the number of such limits does not exceed 99% of the number of issued and outstanding Class B Trust Units; |
| • | Class B Trust Units may be exchanged for Class A Trust Units. However, Pengrowth Corporation will implement a reservation system pursuant to which a reservation number must be obtained for the conversion of Class B Trust Units to Class A Trust Units; |
| • | Class A Trust Units may be exchanged for Class B Trust Units provided that the transferee provides a residency declaration; and |
| • | Class A Trust Units will be registered with CDS, DTC and Computershare in the same manner as the registered and book based system which currently operates in respect of trust units. |
These rules and procedures may be amended from time to time by Pengrowth Trust and Computershare.
Maintaining its status as a mutual fund trust is of fundamental importance to Pengrowth Trust. The negative tax consequences in the event of the loss of Pengrowth’s trust status as a mutual fund trust are summarized under the heading “Risk Factors”.
The Tax Act currently provides that where at any time it can reasonably be considered that a trust is established or is maintained primarily for the benefit of non-resident persons, it will not be a mutual fund trust unless, among other exceptions which are not applicable to Pengrowth Trust, all or substantially all of its property consisted of property other than “taxable Canadian property” at all times since February 21, 1990. The Canadian Federal Budget dated March 23, 2004 (the “Federal Budget”) proposes to amend the Tax Act to provide that for the purpose of this exception Canadian resource property, such as the royalty held by Pengrowth Trust, will be taxable Canadian property. The Federal Budget provides that this amendment will not apply before 2007 to a trust that would otherwise cease on March 23, 2004 to be a mutual fund trust as a result of this newly proposed rule.
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An ADP report received by Pengrowth Trust indicated that the ownership of trust units by non-residents was approximately 53% on the morning of the Federal Budget and was reduced to approximately 48.5% on the same date through the completion of a Canadian only bought deal equity issue of trust units.
It is highly likely that the reclassification can be implemented without adverse tax consequences to unitholders resident either in Canada or in the United States. However, the interpretation and application of some of the relevant provisions of the Tax Act and the Federal Budget are somewhat unclear and the Board of Directors is of the view that the status of Pengrowth Trust as a mutual fund trust could potentially be subject to some risk if non-resident ownership of trust units is allowed to exceed 50% for a material period of time. As the ownership of trust units by non-residents appears to be increasing over time, the Board of Directors considers it very important to implement the reclassification of trust unit capital as soon as possible. To provide certainty to the reclassification, the Board of Directors would prefer to implement the reclassification after obtaining an advance tax ruling or other assurances from CRA acceptable to Pengrowth Trust and the Board of Directors. The advance tax ruling process permits a taxpayer to confirm certain tax consequences of proposed transactions in advance. However, given the time that may be required to obtain an advance tax ruling and the likely increase in non-resident ownership during such period, the Board of Directors has determined that it may be prudent to implement the reclassification of trust unit capital without an advance tax ruling. On balance, the Board of Directors may determine that the preferred course, and the one that exposes the unitholders to the least tax risk, is the practical course of complying as quickly as possible with the Canadian federal government’s apparent policy objective of maintaining foreign ownership of trust units at below 50%.
Exchangeable Shares
At the shareholders’ meeting and royalty unitholders’ meeting conducted on April 22, 2004, amendments were made to the Unanimous Shareholder Agreement to facilitate the issuance of exchangeable shares. The amendments approved will give the Board of Directors greater flexibility to issue a series of exchangeable shares of Pengrowth Corporation which could meet Pengrowth Corporation’s objectives of creating a security that is economically similar to trust units, marketable in Canada, the United States and internationally, with favourable income tax consequences in the offered jurisdictions and that can be issued by Pengrowth Trust without exceeding the residency restrictions under the mutual fund trust requirements of the Tax Act. Among other things, exchangeable shares may provide a valuable alternative source of equity to Pengrowth Corporation to finance ongoing capital commitments of Pengrowth Corporation, new acquisitions and for other general corporate purposes. The exchangeable shares will be securities of Pengrowth Corporation that have rights upon a liquidation, wind-up or dissolution of Pengrowth Corporation (a “Liquidation Event”) that are economically similar to the rights of trust unitholders under the Trust Indenture and Royalty Indenture, except in relation to assets other than royalty units that may be held by Pengrowth Trust and the impact of general claims against Pengrowth Corporation. As a result of the amendments approved, exchangeable shares will have the same rights as the rights of the holders of common shares of Pengrowth Corporation to vote, to dividends or to share splits in lieu of dividends and to the assets of Pengrowth Corporation upon the occurrence of a Liquidation Event.
In addition to the foregoing objective, the exchangeable shares may be eligible for investment by certain classes of investors for whom there are limitations with respect to holding trust units. The exchangeable shares may also facilitate business combinations and acquisitions and may be issued to Pengrowth Management should there be a wind-up or termination of the Management Agreement.
The creation of exchangeable shares was originally approved by unitholders at the Annual and Special Meetings held on June 17, 2003. It was contemplated at that time if a Liquidation Event were to occur, that holders of exchangeable shares would exercise their exchange right for trust units and would participate along with trust unitholders in accordance and provisions prescribed by the Royalty Indenture and the Trust Indenture. However, a series of exchangeable shares may, from time to time, be issued that would limit the right of exchange to holders of exchangeable shares who are resident in Canada or the right of exchange may otherwise be prescribed in terms of Class B Trust Units and the conditions of ownership thereof.
In order not to disenfranchise any holders of exchangeable shares and to create clear rights with respect to the assets of Pengrowth Corporation subject to claims against Pengrowth Corporation, unitholder approval was obtained to make appropriate amendments to the Royalty Indenture to create insolvency rights with respect to the assets of Pengrowth Corporation which are economically similar to the rights of trust unitholders under the Trust Indenture and the Royalty Indenture. Although economically similar, these rights are distinct from the rights of holders of trust units in that the holders of exchangeable shares shall only have a claim against the assets of Pengrowth Corporation if a Liquidation Event
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shall occur and shall have no claim against the cash or other assets of Pengrowth Trust. The exchangeable shares, shall in the same manner as the common shares, be subject to claims made against the Corporation generally.
Upon a Liquidation Event, an amount will be withheld from the assets or monies available for distribution to royalty unitholders under the Royalty Indenture to be paid to holders of the exchangeable shares and common shares representing the proportion of the economic interests in Pengrowth Corporation represented by the exchangeable shares and in the common shares compared with the beneficial economic interest in Pengrowth Corporation held by the trust unitholders (through the royalty units held by Pengrowth Trust).
New Long-Term Incentive Plan
The unitholders approved a new long-term incentive program and the grant of up to 250,000 phantom units and corresponding treasury units to executive officers of Pengrowth Corporation in accordance with the terms of the program. The mechanics of the program are as follows:
| • | The Board of Directors will allocate phantom trust units under the program to executive officers of Pengrowth Corporation from time to time as part of their total compensation. Subject to vesting conditions to be determined by the Board of Directors, the phantom trust units can be exchanged by holders at any time for trust units to be issued from treasury for nil consideration. |
| • | The phantom trust units will typically vest over a period of two years after the initial grant and the Board of Directors may prescribe other conditions for vesting such as personal performance or performance by Pengrowth Trust. |
Phantom distributions will be paid on the phantom trust units in the form of the issuance of additional phantom trust units based upon a deemed reinvestment formula using a 20-day weighted average market price and any phantom distributions so paid shall be considered to be fully vested phantom trust units.
Amendments to Unanimous Shareholders Agreement
Amendments to the Unanimous Shareholder Agreement were approved in order to: (i) provide that the special voting unit of Pengrowth Trust will be entitled to a number of votes at any meeting of the shareholders of Pengrowth Corporation equal to the number of outstanding Exchangeable Shares (to provide voting rights for Exchangeable Shares that do not otherwise have voting rights); (ii) provide voting rights to the Common Shares and to any series of Exchangeable Shares that are provided with voting rights at the time they are created by the Board of Directors; (ii) permit stock splits of the Common Shares on equivalent terms to the Exchangeable Shares; and (iii) delete Article V of the Unanimous Shareholders Agreement which prohibits the issuance of additional shares of Pengrowth Corporation. These amendments are required to achieve the desired financial and tax consequences for the Exchangeable Shares.
Trends
There are a number of business and economic factors which underlie trends in the oil and gas industry that influence the near term future of our business.
The conversion of traditional oil and gas companies into income and royalty trusts has continued in 2003. The proliferation of income and royalty trusts, the efforts of these trusts to replace annual production declines and robust oil and natural gas prices have resulted in a very competitive market for the acquisition of oil and gas properties and related assets. There has been a corresponding increase in the valuation parameters for corporate and asset acquisitions, while at the same time income and royalty trusts, including Pengrowth Trust, have enjoyed favourable access to equity and debt capital markets.
Commodity prices, while volatile, are at relatively high levels compared with historical averages, with oil prices currently at thirteen-year highs. However, the appreciation of the Canadian dollar in 2003 relative to the U.S. dollar has offset a portion of the economic benefit to Canadian oil and gas producers, including trusts, of these higher prices. Increases or decreases in the Canadian dollar relative to the U.S. dollar also result in decreases or increases, respectively, in revenues as operating costs are denominated in Canadian dollars. The Canadian dollar was strong in early 2004, but has weakened as of late.
At the same time, interest rates have been at 42-year record lows, providing a significant stimulative impact on the North American economy.
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For additional information regarding Pengrowth Trust’s strategy in this business environment, see “Management’s Discussion and Analysis — Outlook” on page 65 of Pengrowth Trust’s 2003 Annual Report.
PENGROWTH MANAGEMENT LIMITED
Business
The principal business of Pengrowth Management is that of a specialty fund manager. Pengrowth Management currently provides advisory, management, and administrative services primarily to Pengrowth Trust and Pengrowth Corporation. Pengrowth Management also previously provided investment advisory and management services in relation to investments by several Canadian pension funds in the energy sector. These investments were subsequently acquired by Pengrowth Corporation for royalty units and cash. Pengrowth Management utilizes its extensive experience and employs prudent oil and gas business practices to increase the value of the assets of Pengrowth Corporation through effective acquisitions and dispositions and through effective operations. Pengrowth Management has focused upon high quality, long life proven producing properties located in Canada. Pengrowth Management will continue to focus upon acquisitions which are strategic and which add value to Pengrowth Corporation and Pengrowth Trust on a per unit basis.
Management Agreement
The unitholders and the holders of royalty units approved an amended and restated management agreement among Pengrowth Trust, Pengrowth Corporation, Pengrowth Management and Computershare, as trustee (the “Management Agreement”) at annual and special meetings held on June 17, 2003. The Management Agreement governs both Pengrowth Trust and Pengrowth Corporation. The Board of Directors negotiated the Management Agreement with Pengrowth Management, to incentisize future performance and to avoid the upfront termination payments associated with internalizations.
Key elements of the Management Agreement are:
| • | two distinct 3-year terms with a declining fee structure in the second 3-year term; |
| • | a base fee determined on a sliding scale: |
| • | in the first three-year contract term: |
| • | 2% of the first $200 million of Income; and | |||
| • | 1% of the balance of Income over $200 million; and | |||
| • | in the second three-year contract term: |
| • | 1.5% of the first $200 million of Income; and | |||
| • | 0.5% of the balance of Income over $200 million. | |||
(For these purposes, “Income” means the aggregate of net production revenue of Pengrowth Corporation and any other income earned from permitted investments of Pengrowth Trust (excluding interest on cash or near-cash deposits or similar investments).
| • | a performance based fee based on total returns received by unitholders which essentially compensates Pengrowth Management for total annual returns which average in excess of 8% per annum over a 3-year period; |
| • | a ceiling on total fees payable determined in reference to a percentage of the fees paid under the previous management agreement: 80% each year in the first three-year contract term and 60% each year in the second three-year contract term and subject to a further ceiling essentially equivalent to $12 million annually during the second three-year contract term; |
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| • | requirement for Pengrowth Management to pay certain expenses of Pengrowth Corporation and Pengrowth Trust of approximately $2 million per year; |
| • | an annual minimum management fee of $3.6 million comprised of $1.6 million of management fees and $2.0 million of expenses; |
| • | key man provisions in respect of James S. Kinnear, the President of Pengrowth Management; |
| • | a bonus structure based on 10% of Pengrowth Management’s base fee for employees and special consultants of Pengrowth Corporation; and |
| • | an optional buyout of the Management Agreement at the election of the Board of Directors upon the expiry of the first three-year contract term with a termination payment of essentially 2/3 of the management fee paid during the first three-year contract term plus expenses of termination. |
The responsibilities of Pengrowth Management under the Management Agreement include:
| • | reviewing and negotiating acquisitions for Pengrowth Corporation and Pengrowth Trust; |
| • | providing written reports to the Board of Directors to keep Pengrowth Corporation fully informed about the acquisition, exploration, development, operation and disposition of properties, the marketing of petroleum substances, risk management practices and forecasts as to market conditions; |
| • | supervising Pengrowth Corporation in connection with its acting as operator of certain of its properties; |
| • | arranging for, and negotiating on behalf of, and in the name of, Pengrowth Corporation all contracts with third parties for the proper management and operation of the properties of Pengrowth Corporation; |
| • | supervising, training and providing leadership to the employees and consultants of Pengrowth Corporation and assisting in recruitment of key employees of Pengrowth Corporation; |
| • | arranging for professional services for Pengrowth Corporation and Pengrowth Trust; |
| • | arranging for borrowings by Pengrowth Corporation and equity issuances by Pengrowth Trust; and |
| • | conducting general unitholder services, including investor relations, maintaining regulatory compliance, providing information to unitholders in respect of material changes in the business of Pengrowth Corporation or Pengrowth Trust and all other reports required by law, and calling, holding and distributing material in respect of meetings of unitholders and holders of royalty units. |
Despite the broad authority of Pengrowth Management, approval of the Board of Directors is required on decisions relating to any offerings, including the issuance of additional trust units, acquisitions in excess of $5 million, annual operating and capital expenditure budgets, the establishment of credit facilities, the determination of cash distributions paid to unitholders, the amendment of any of the constating documents of Pengrowth Corporation or Pengrowth Trust and the amount of the assumed expenses of Pengrowth Management which are a portion of the compensation of Pengrowth Management.
Management Fee
Pengrowth Management received $695,000 for acquisition fees, $9,661,349 for management services and $520,000 as performance fees in 2003. Although the management fee rate decreased effective July 1, 2003, there was an increase in total management fees compound to 2002 due to the higher fee base in 2003. Management fees are calculated on a percentage of “net operating income” (oil and gas sales and other income, less royalties, operating costs, solvent amortization and reclamation funding.) The base fee has been reduced from a sliding scale between 3.5% and 2.5%, to the new rate of 2% on the first $200 million of net operating income and 1% on net operating income over $200 million. Acquisition fees have been eliminated (effective July 1, 2003), and Pengrowth Management is eligible to receive a “performance fee” if certain performance criteria are met. The previous fee arrangements remain relevant however as there
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is a cap imposed on the fees, including the performance fee, limiting the aggregate of such fees to 80% of the fees that would otherwise have been paid under the old management agreement (inclusive of acquisition fees) for the first three years, and 60% for the second three years.
Bonus Pool
As an incentive to officers, employees and special consultants of Pengrowth Management (including employees of Pengrowth Corporation but excluding the President, James S. Kinnear), a bonus pool has been established which is carved out from the management fee paid to Pengrowth Management, determined as 10% of the total fees received by Pengrowth Management (ie. 10% of the management fee and any performance fee earned). Bonuses are paid from time to time in accordance with criteria to be set at the discretion of Pengrowth Management as a further incentive for performance.
PENGROWTH CORPORATION — OPERATIONAL INFORMATION
As at December 31, 2003, Pengrowth Corporation had 217 permanent employees. Pengrowth Corporation has invested more than $1.95 billion in the energy sector primarily to purchase mature, proven producing oil and natural gas properties in Canada.
Principal Properties
The portfolio of properties acquired and held by Pengrowth Corporation primarily includes relatively long life, oil and gas producing properties with established production profiles.
Pengrowth Corporation obtained the GLJ Report dated February 19, 2004 in respect to the oil and gas properties of Pengrowth Corporation effective December 31, 2003. All reserve data presented under this sub-heading is based on the GLJ Report.
Pengrowth Corporation’s producing properties are summarized in the following table:
Summary of Property Interests Held by Pengrowth Corporation as at December 31, 2003
| Pengrowth Total | ||||||||||||||||||||||||
| Proved Plus | 2003 Actual Oil | 2004 Estimated Oil | ||||||||||||||||||||||
| Remaining | Reserve | Probable | Value at 12% | Equivalent | Equivalent | |||||||||||||||||||
| Reserve Life | Life Index | Reserves(3) | Discount | Production(3) | Production(3) | |||||||||||||||||||
| (Years) | (Years) | (mboe) | ($M) | (boepd) | (boepd) | |||||||||||||||||||
| Judy Creek BHL Unit | 50 | 11.7 | 43,552 | 282,012 | 10,359 | 10,197 | ||||||||||||||||||
| Judy Creek West BHL Unit | 50 | 13.5 | 10,451 | 32,874 | 1,946 | 2,129 | ||||||||||||||||||
| SOEP | 10 | 7.2 | 18,746 | 181,021 | 7,620 | 7,133 | ||||||||||||||||||
| Weyburn Unit | 39 | 18.8 | 14,641 | 43,787 | 2,091 | 2,128 | ||||||||||||||||||
| Swan Hills Unit No.1 | 50 | 23.0 | 11,325 | 40,267 | 1,455 | 1,348 | ||||||||||||||||||
| Dunvegan Gas Unit No. 1 | 45 | 16.1 | 6,140 | 30,998 | 972 | 1,046 | ||||||||||||||||||
| Oak | 42 | 9.9 | 5,343 | 48,591 | 1,052 | 1,474 | ||||||||||||||||||
| Rigel | 20 | 5.4 | 4,705 | 50,044 | 2,996 | 2,404 | ||||||||||||||||||
| Monogram Gas Unit | 38 | 12.8 | 7,071 | 51,132 | 1,363 | 1,508 | ||||||||||||||||||
| Enchant | 40 | 13.3 | 3,821 | 18,448 | 826 | 784 | ||||||||||||||||||
| McLeod River | 28 | 7.4 | 4,679 | 33,599 | 1,760 | 1,725 | ||||||||||||||||||
| Squirrel | 20 | 5.7 | 2,638 | 24,885 | 1,779 | 1,271 | ||||||||||||||||||
| Kaybob Notikewin Unit No. 1 | 43 | 12.8 | 3,512 | 24,994 | 811 | 754 | ||||||||||||||||||
| Quirk Creek | 32 | 10.9 | 3,610 | 28,520 | 1,023 | 907 | ||||||||||||||||||
Other B.C.(1) | 50 | 7.1 | 12,448 | 105,043 | 5,164 | 4,759 | ||||||||||||||||||
Other(2) | 50 | 10.7 | 31,734 | 254,709 | 7,816 | 8,092 | ||||||||||||||||||
| Total | 50 | 10.6 | 184,416 | 1,250,924 | 49,033 | 47,659 | ||||||||||||||||||
Source: GLJ Report
| Notes: | ||
| (1) | “Other B.C.” includes Pengrowth’s working interest in 30 other properties. | |
| (2) | “Other” includes Pengrowth Corporation’s working interest in 27 other properties. | |
| (3) | Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe. | |
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Judy Creek Beaverhill Lake Unit and Judy Creek West Beaverhill Lake Unit
Pengrowth Corporation holds a 100% working interest in the Judy Creek Beaverhill Lake Unit (the “Judy Creek A Pool”) and a 98.38% working interest in the Judy Creek West Beaverhill Lake Unit (the “Judy Creek B Pool”), (together “Judy Creek”). Judy Creek is located approximately 200 kilometres northwest of Edmonton in North-Central Alberta and covers an area of approximately 155 square kilometres (60 sections). Judy Creek was discovered in 1959, placed on waterflood (secondary recovery) in 1962 and miscible flood (tertiary recovery) in 1985. Original oil in place totalled 815 mmbbls of oil in the Judy Creek A Pool, making it one of the largest oil pools discovered in western Canada. To December 31, 2003, a total of 347.6 mmbbls have been produced from the Judy Creek A Unit, before royalties. Remaining Total Proved Plus Probable Reserves at December 31, 2003 are estimated at 43.5 mmboe. Original oil in place at the Judy Creek B Unit totalled 262 mmbbls and, as at December 31, 2003, 118 mmbbls have been produced, before royalties. Original oil in place at the Judy Creek A and B Pools combined totals 1,077 mmbbls, with an aggregate of 465.6 mmbbls produced as at December 31, 2003. Pengrowth’s average production for Judy Creek in 2003 was 12,535 boepd (before royalties), the remaining producing reserve life is 50 years and the Reserve Life Index is 11.7 and 13.5 years respectively for the A and B pools.
Development Activity
Pengrowth Corporation operates both the Judy Creek A and B Pools. Pengrowth Corporation has continued the enhanced oil recovery program that was initiated at Judy Creek in 1985. In the Judy Creek hydrocarbon miscible flood program, oil production is increased by injecting a light, hydrocarbon-based solvent (ethane and methane) into the reservoir. In 2003, solvent was injected at 13 solvent injection wells and Pengrowth Corporation is anticipating increased oil production from up to 43 offsetting production wells.
New development continued in 2003 with the drilling of four oil wells and three water/solvent injection wells in the Judy Creek A Pool.
There may be other methods of enhancing future production in Judy Creek including the use of C02 as a solvent, potentially reducing solvent costs, or developing the coal bed methane potential on Pengrowth Corporation’s acreage. Coal bed methane technology in Canada is still in the developmental stage, but is being researched by a number of major oil and gas companies. Coal bed methane technology is more advanced in the United States where coal bed methane resources have been successfully harnessed for economic gas production.
During 2003, Pengrowth Corporation continued to focus on reducing operating costs at Judy Creek and improving productivity with acid fracs and injector booster pumps. Pengrowth Corporation also optimized the use of onsite solvent to minimize the cost of solvent purchases.
Development plans in 2004 include drilling up to five new oil wells, four horizontal injection wells and three gas wells targeting shallow natural gas reservoirs.
Sable Offshore Energy Project
The Sable Offshore Energy Project is located offshore the Province of Nova Scotia. On June 15, 2001, Pengrowth Corporation acquired a 99.9% royalty interest in the reserves and production associated with Emera Offshore Incorporated’s 8.4% working interest and was responsible for its royalty share of associated capital and operating costs.
On May 8, 2003, Pengrowth Corporation acquired an 8.4% working interest in all of the SOEP production facilities downstream of the Thebaud Central Processing Platform in conjunction with the adjustment of various operating and processing expenses with Emera for a net consideration of approximately $57 million. As a result of the acquisition Pengrowth Corporation is no longer paying processing fees in respect to the downstream facilities and the economic interests of Pengrowth Corporation will be better aligned with those of the other SOEP co-venturers. Although the acquisition of these facilities does not increase Pengrowth’s SOEP reserves, the acquisition of these facilities does increase the present value of future cash flows from the SOEP reserves by reducing future operating costs. Effective December 31, 2003, Pengrowth acquired an 8.4% working interest in the SOEP offshore platforms and associated sub-sea field gathering lines from Emera and exchanged the royalty interest previously held for a working interest in the SOEP reserves for a total purchase price of $65 million. As a result of these two transactions, Pengrowth now holds an 8.4% working interest in the overall SOEP project. The acquisition of SOEP facilities interests in 2003 initially reduces Pengrowth Corporation’s annual operating costs by $28 to $30 million.
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As of December 31, 2003, the total SOEP remaining Total Proved Plus Probable Reserves are estimated by GLJ to be 1.1 tcf of natural gas and 41 mmbbls of NGLs and Pengrowth Total Proved Plus Probable Reserves are estimated to be 92 bcf of natural gas and 3.5 mmbbls of NGLs. Pengrowth’s working interest share of SOEP production averaged 36.7 mmcfpd of sales gas and 1,500 bblpd of NGLs in 2003 (before royalties).
The SOEP gas reserves were discovered in the early 1970’s and commercial gas production began in December 1999. SOEP currently produces gas and NGLs from four fields in the vicinity of Sable Island, Nova Scotia: Venture, North Triumph and Thebaud and Alma. The SOEP project consists of two tiers. The first tier, completed in December 1999, included the construction of the main gas processing plant at Goldboro, a natural gas liquids fractionation plant at Point Tupper, offshore platforms at Thebaud, North Triumph and Venture and the offshore pipeline system. The second tier encompasses the development of the Alma and South Venture fields and development activity, including further drilling, is expected to continue through 2008. The Alma platform was tied back to the Thebaud platform in October, 2003 and the field came on-stream in November 2003 at a total rate of 120 mmcfpd of which Pengrowth’s working interest share was 10.1 mmcfpd (before royalties).
One well was drilled in the South Venture field in late 2002 and is awaiting completion pending installation of the production platform and at least two more are planned after the platform is installed. Fabrication of facilities began in March 2003 with construction approximately 50% complete at year end. The South Venture field is expected to commence in late 2004.
The first development well in the Glenelg field was drilled and abandoned in the first quarter of 2003. Development of Glenelg has been deferred and future plans for production at Glenelg are currently being re-evaluated. Glenelg was originally included in the second tier development plans.
Sales gas from SOEP is delivered to the onshore gas plant facility at Goldboro, and the liquids are processed at the fractionation plant in Point Tupper. The refined gas is transported to market via the Maritimes & Northeast Pipeline.
With long term opportunities in mind, Pengrowth acquired Nova Scotia Resources Limited’s interests in 11 Significant Discovery Licences in May 2003 for $4.5 million plus a 10 % net profits interest (“NPI”). The NPI starts after the payment of capital invested plus a rate of return allowance. These licences indicate that previous exploratory drilling has discovered hydrocarbon resources. Further drilling will be required to prove up economic reserves. The working interests in the licences range from 1.5 to 10%.
Weyburn Unit
Pengrowth Corporation holds a 9.75% working interest in the Weyburn Unit located approximately 120 kilometres southeast of Regina in southeast Saskatchewan. The Weyburn Unit encompasses approximately 216 square kilometres. Production commenced from the Midale formation in 1955 under primary depletion (solution gas expansion). The Weyburn Unit was formed in 1963 for the purpose of implementing an inverted nine-spot waterflood pressure maintenance scheme. Commencing in 1985, the operator, PanCanadian Petroleum Limited (now EnCana Corporation), embarked on an extensive infill drilling and waterflood reconfiguration program. In recent years horizontal wells have been extensively used to arrest production declines. Produced oil averages 31° API and contains approximately 2% sulphur. GLJ estimates a remaining Total Proved Plus Probable Reserves at December 31, 2003 of 150.1 mmboes of oil (Pengrowth Total Proved Plus Probable Reserves are estimated to be 14.6 mmboes) with a remaining producing life of 38.5 years and a Reserve Life Index of 18.8 years. In 2003, gross lease production from the Weyburn Unit averaged 21,454 boepd from 749 (89 net) oil wells, of which Pengrowth’s working interest share was 2,091 boepd (before royalties).
Development Activity
A carbon dioxide (CO2) miscible flood project was initiated in the fall of 2000. CO2 injection has been initiated in thirty two patterns in phases 1A, 1B and 1C of the flood. Recent development activity included 23 horizontal infill wells in 2001, 5 horizontal wells and various waterflood enhancement programs in 2002 and 7 horizontal infill wells in 2003. Including December 2003 data, the CO2 pattern development area now contributes 57% of total production at the Weyburn Unit. Current gross lease incremental production directly due to the CO2 miscible scheme is estimated at 8,800 bblpd of which Pengrowth’s working interest share is estimated at 858 bblpd (before royalties).
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Swan Hills Unit No. 1
Pengrowth Corporation holds a 10.45% working interest in the Swan Hills Unit No. 1 located approximately 180 kilometres northwest of Edmonton in North-Central Alberta. The Swan Hills Beaverhill Lake A and B pools were discovered and placed on production in 1957. The pools were unitized in 1963 to facilitate the implementation of a line drive waterflood project. Swan Hills Unit No. 1 is the second largest producing crude oil unit in Canada, producing a total lease average of 13,925 boepd in 2003 and is operated by Devon Canada Ltd. In 2003, Pengrowth’s working interest share of production was 1,455 boepd before royalties. GLJ estimates that the remaining Total Proved Plus Probable Reserves at December 31, 2003 are 94.3 mmbbls of oil, 65.4 bcf of natural gas and 3.2 mmbbls of NGLs (Pengrowth Total Proved Plus Probable Reserves are estimated to be 9.9 mmbbls of oil, 6.8 bcf of natural gas and 0.3 mmbbls of NGLs) with a remaining producing life of 50 years and a Reserve Life Index of 23 years.
Development Activity
Development activities in the Swan Hills Unit No. 1 during 2003 included successful drilling of three northwest platform wells and three recompletions. More platform drilling is anticipated for 2004 and a CO2 miscible pilot project was approved.
Dunvegan Gas Unit No. 1
Pengrowth Corporation holds a 7.97% working interest in the Dunvegan Unit located near Fairview, Alberta, in the Peace River Arch, approximately 430 kilometres northwest of Edmonton. The Dunvegan natural gas field is operated by Devon Canada Corporation, has 129 (10 net) producing natural gas wells and covers an area of approximately 213 square kilometres. Approximately 95% of the Dunvegan Unit’s identified natural gas reserves are contained in the Mississippian Debolt formation at a depth of approximately 1,465 meters. A natural gas processing plant, a gathering system and satellite facilities were built in 1973. A deep cut facility was completed in 1987 for the purpose of extracting propane, butane and heavier natural gas liquids from the raw natural gas stream. Sour gas processing facilities were added in 1996. A natural gas storage project also exists in the Dunvegan Unit.
GLJ estimates that Total Proved Plus Probable Reserves of 341.9 bcf of natural gas and 20.1 mmbbls of NGLs (Pengrowth Total Proved Plus Probable Reserves of 27.2 bcf of natural gas and 1.6 mmbbls of NGLs) remain to be produced from the Dunvegan Unit as at December 31, 2003. It has a remaining life of 45 years and a Reserve Life Index of 16.1 years. Current production from the Dunvegan Unit is obtained from five zones. In 2003, Pengrowth Corporation’s working interest share of production averaged 972 boepd (before royalties). The majority of gas from the Dunvegan Unit is currently being sold under contract to Progas Limited with the remainder going to Pan-Alberta Gas Ltd. and other direct markets.
Development Activity
Development activity at the Dunvegan Unit was very high and successful in 2003 with 12 new gas wells drilled and 14 recompletions of existing producers. The operator proposes increased development in 2004, including 24 new wells and 12 recompletions.
Oak
The Oak area is located in northeastern British Columbia and is approximately 20 kilometers north of Fort St. John. The property consists of 29 operated oil and natural gas wells, six injection wells and seven water source wells surrounding two batteries and three natural gas compressors. Pengrowth Corporation also holds a 20.6% working interest in the non-operated Oak Cecil “I” Unit #1. Production is obtained from the Halfway, Cecil, Baldonnel, Cadomin and Bluesky formations. One injector was drilled in 2003 to optimize the waterflood and enhance Cecil oil production and reserves recovery within the area. Also, two vertical Baldonnel gas wells were drilled in 2004 with one tied in and producing at a total rate of 500 mcfpd before royalties; the other well is still under evaluation.
Pengrowth’s working interest share of production averaged 1,052 boepd (before royalties) for 2003.
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Development Activity
Oak “C” unitization was completed, with gas injection commencing in February, 2003 and water injection in April, 2003. The pool is estimated to see increased production, in 2004, due to waterflood response. It is estimated an incremental two million barrels of oil is recoverable with the waterflood. The Baldonnel development drilling program will continue in 2004.
Rigel
The Rigel area is located in northeastern British Columbia and is approximately 40 kilometers north of Fort St. John. Pengrowth Corporation holds an average 60% working interest in the property. The property consists of four Cecil oil pools containing 39 oil wells, 19 injection wells, a central battery, and a solution gas compressor. One new edge well was drilled and abandoned in 2003.
Optimization of pumping equipment is ongoing and stimulations of selected injectors will continue to optimize the waterflood. Pengrowth’s working interest share of production averaged 2,996 boepd (before royalties) in 2003.
Development Activity
No new wells are currently budgeted.
Monogram Gas Unit
Pengrowth Corporation’s working interest in the Monogram Gas Unit, located in southern Alberta, is 53.82%. The Monogram Gas Unit produces sweet, dry natural gas from the Medicine Hat, Milk River and Second White Specks formations. Pengrowth’s working interest share of 2003 production averaged 8.2 mmcfpd from 366 wells (197 net). Pengrowth Total Proved Plus Probable Reserves are estimated to be 42.4 bcf.
A successful 40-well infill drilling program was completed in 2001. The operator is currently evaluating a 154 well infill program for 2004. The facilities will be upgraded with the addition of compression and line looping in order to accommodate production from the new wells. It is anticipated that the infill drilling program will double Pengrowth’s production from Monogram by the end of 2004.
Enchant
The Enchant property is located approximately 120 miles southeast of Calgary. The property consists of four operated oil pools in which Pengrowth Corporation holds an average 88% working interest. These pools produce 32° API oil from the Nisku formation. Pengrowth’s working interest share of production from Enchant averaged 826 boepd (before royalties) for 2003.
Pengrowth Corporation holds a 99% working interest in the largest pools (the J and VV pool) which consists of 33 producing and 10 injection wells with treating, water handling and gas conservation handled at a central battery. Primary production commenced in 1992 and a waterflood project was implemented in 1995. GLJ estimates that the Enchant property has a Reserve Life Index of 13 years.
In the Enchant Arcs Unit No. 2, where Pengrowth Corporation converted a well to injection in mid-2000, pressure support is now apparent and water break through is being observed in our oil producers.
Development Activity
Pengrowth Corporation is currently evaluating drilling one potential oil well in the Arcs Unit in 2004 to capture bypassed reserves due to water breakthrough.
McLeod River
The McLeod River property is located approximately 70 miles from Edmonton. Production is obtained from the Rock Creek, Notikewin, Gething and Cardium formations. Pengrowth Corporation drilled eight gas wells during 2003,
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with working interests between 30% and 100%. Three wells are tied-in and are on production, one is awaiting tie-in and the other wells are under evaluation. Pengrowth’s working interest share of production from McLeod River averaged 1,760 boepd (before royalties) for 2003.
Development Activity
To date in 2004, one well has been drilled, completed and is on production and a second well has been drilled and is awaiting to be completed. Four to seven additional wells are planned to be drilled in the second half of 2004.
Squirrel
The Squirrel area located in North Eastern British Columbia approximately 48 kilometers north of Fort St. John consists of 12 producing oil wells, four water injection wells, a gas injection well, a central battery and a compressor station. The oil wells were either drilled or acquired in 2000 to obtain production from the Triassic North Pine formation. A gas re-injection project was implemented during November 2000 to maintain pool pressure and increase oil production. With the commencement of water injection, gas injection has been reduced to 10 days per month. During 2001, a waterflood was implemented to maximize reserve recovery. One oil well was fracture stimulated with positive results. We are currently assessing other fracture candidates. Pengrowth’s working interest share of production from Squirrel averaged 1,779 boepd (before royalties) 2003.
Development Activity
In 2004, Pengrowth will evaluate the conversion of one oil well to water injection to improve the waterflood and reduce the need for gas injection. We will continue to optimize the existing pumping equipment to improve oil production. We are evaluating concurrent production approval of the gas cap and also potential infill drilling for enhanced waterflood recovery.
Kaybob Notikewin Unit No. 1
Pengrowth Corporation’s working interest in the Kaybob Notikewin Unit No. 1 is 64.5%. The property produces natural gas and natural gas liquids, with 19 producing wells (12.3 net) in the Kaybob Notikewin Unit. The estimated Reserve Life Index of the property is 12.8 years.
In 2003, Pengrowth’s working interest share of production averaged 811 boepd (before royalties). GLJ estimates Pengrowth Total Proved Plus Probable Reserves at December 31, 2003 to be 3.5 mmboe.
Plans for 2004 include reviewing the long term inactive wells.
Quirk Creek
Pengrowth Corporation holds a 55.9% working interest in three producing deep plate gas wells, a 26.4% working interest in 10 other producing shallow plate gas wells, a 5.5% working interest in 13 producing gas wells and a 30.5% working interest in the Quirk Creek natural gas plant located in the Quirk Creek areas of Southern Alberta. This compares to Pengrowth Corporation’s previous 5.5% working interest in 13 producing gas wells in the area and a 4.6% in the gas plant. Rated at 80 million cubic feet per day of raw inlet gas, the Quirk Creek gas plant currently operates at about 90% of capacity.
Pengrowth working interest share of production for 2003 was approximately 4.8 mmcfpd of natural gas and 219 bpd of natural gas liquids (before royalties). Pengrowth’s remaining Total Proved Plus Probable Reserves are estimated at 3.6 mmboe, consisting of 16.8 bcf of natural gas and 0.8 mmbbls of NGLs.
Pengrowth Corporation believes significant upside potential exists for future gas development and processing revenue in the area.
Reserves
The effective date of the information in this section is December 31, 2003 and the preparation date of the information is January 30, 2004. The information in this section is based upon an evaluation by GLJ with an effective date
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of December 31, 2003 contained in the GLJ Report dated February 19, 2004. The information in this section summarizes the oil, liquids and natural gas reserves of Pengrowth Corporation and the net present values of future net revenue for these reserves using GLJ’s constant prices and costs and forecast prices and costs and conforms with the requirements of NI 51-101. Pengrowth Corporation engaged GLJ to provide an evaluation of proved reserves and proved plus probable reserves and no attempt was made to evaluate possible reserves. It is Pengrowth’s practice to obtain an engineering report evaluating all of its reserves as at December 31 of each year.
All of Pengrowth Corporation’s reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia (SOEP offshore).
The following tables set forth certain information relating to the oil and natural gas reserves of Pengrowth Corporation and the present value of the estimated future net cash flow associated with such reserves as at December 31, 2003. The information set forth below is derived from the GLJ Report which has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook and the reserves definitions contained in NI 51-101 and the Canadian Oil and Gas Evaluation Handbook. The GLJ Report incorporates estimates of future well abandonment obligations but does not include estimates of remediation costs.All evaluations of future net cash flow are stated prior to any provision for income taxes, interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.
In 2003, the securities regulatory authorities in Canada (other than Québec) adopted National Instrument 51-101 —Standards of Disclosure for Oil and Gas Activitieswhich imposes new oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. Under the new reserve categories, reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward based on:
| (a) | analysis of drilling, geological, geophysical and engineering data; | |||
| (b) | the use of established technology; and | |||
| (c) | specified economic conditions. | |||
Reserves are classified according to the degree of certainty associated with the estimates.
| (d) | Proved Reservesare those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. | |||
| (e) | Probable Reservesare those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. | |||
Reported reserves should target the following levels of certainty under a specific set of economic conditions:
| • | at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and |
| • | at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. |
A qualitative measure of the certainty levels pertaining to the estimates prepared for the various reserve categories is desirable to provide an understanding of the associated risks and uncertainties. However, the majority of reserve estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure
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of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
Pengrowth Corporation is entitled to claim Alberta Royalty Credits. The Alberta Royalty Credits program is based on a price-sensitive formula linked to crude oil prices. Credits vary from a high of 75% of the eligible Alberta Crown Royalties for a taxation year to a maximum of $1,500,000 (75% of $2,000,000) when the price of oil falls below U.S. $15 per barrel, to a low of 25% (maximum $500,000) when the price of oil rises above U.S. $30 per barrel. In the GLJ Report, this program is assumed to continue indefinitely.
The net cash flows estimated in the GLJ Report represent estimates of the revenues from oil and gas sales from the petroleum and natural gas properties of Pengrowth Corporation together with an estimate of processing revenues less royalties (net of incentives), mineral taxes, field operating expenses and capital obligations. These net cash floes are not the same as the distributable cash reported by Pengrowth Trust. Reference is made to the audited consolidated financial statements of Pengrowth Trust for the year ended December 31, 2003 for the computation of distributable cash and in particular to the consolidated statements of income, the consolidated statements of cash flow and note 4 to the financial statements headed “Distributable Cash”. Significant factors to consider include:
| (a) | the GLJ Report does not estimate general and administrative expenses, interest, management fees and holdbacks; | |||
| (b) | for purposes of calculating distributable income, Pengrowth Trust amortizes the cost of miscible flood injection fluids purchased from third parties over the period of expected future economic benefit arising from the injection of those fluids, which is currently 30 months. The GLJ Report includes the full cost of purchased injection fluids ($21.2 million in 2003) in operating costs in the year incurred; and | |||
| (c) | Pengrowth Corporation withholds approximately 10% of distributable cash to fund capital. | |||
In accordance with the requirements of NI 51-101, the Report on Reserves Data by Independent Qualified Reserves Evaluator in Form 51-101F2 and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached as Appendices A and B hereto, respectively.
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2003
CONSTANT PRICES AND COSTS
| OIL AND GAS RESERVES | |||||||||||||||||||||||||||||||||||||
| LIGHT AND | NATURAL GAS | ||||||||||||||||||||||||||||||||||||
| MEDIUM OIL | NATURAL GAS | LIQUIDS | |||||||||||||||||||||||||||||||||||
| Pengrowth | Working | Pengrowth | Working | Pengrowth | Working | ||||||||||||||||||||||||||||||||
| Interest | Interest(2) | Net | Interest | Interest(2) | Net | Interest | Interest(2) | Net | |||||||||||||||||||||||||||||
| RESERVES CATEGORY | (mbbls) | (mbbls) | (mbbls) | (bcf) | (bcf) | (bcf) | (mbbls) | (mbbls) | (mbbls) | ||||||||||||||||||||||||||||
| Proved | |||||||||||||||||||||||||||||||||||||
| Developed Producing | 61,402 | 61,279 | 51,423 | 278 | 272 | 220 | 12,977 | 12,818 | 9,146 | ||||||||||||||||||||||||||||
| Developed Non-Producing | 502 | 501 | 421 | 12 | 11 | 9 | 237 | 231 | 190 | ||||||||||||||||||||||||||||
| Undeveloped | 17,655 | 17,641 | 14,946 | 54 | 52 | 42 | 1,585 | 1,534 | 1,129 | ||||||||||||||||||||||||||||
| Total Proved | 79,559 | 79,421 | 66,790 | 343 | 336 | 271 | 14,799 | 14,583 | 10,464 | ||||||||||||||||||||||||||||
| Probable | 18,855 | 18,821 | 15,785 | 76 | 72 | 57 | 3,598 | 3,513 | 2,578 | ||||||||||||||||||||||||||||
| Total Proved Plus Probable | 98,414 | 98,241 | 82,575 | 419 | 408 | 329 | 18,393 | 18,096 | 13,044 | ||||||||||||||||||||||||||||
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| TOTAL OIL | ||||||||||||
| EQUIVALENT BASIS(1) | ||||||||||||
| Pengrowth | Working | |||||||||||
| Interest | Interest(2) | Net | ||||||||||
| RESERVES CATEGORY | (mboe) | (mboe) | (mboe) | |||||||||
| Proved | ||||||||||||
| Developed Producing | 120,663 | 119,439 | 97,220 | |||||||||
| Developed Non-Producing | 2,693 | 2,637 | 2,125 | |||||||||
| Undeveloped | 28,174 | 27,808 | 23,141 | |||||||||
| Total Proved | 151,530 | 149,884 | 122,486 | |||||||||
| Probable | 35,038 | 34,383 | 27,938 | |||||||||
| Total Proved Plus Probable | 186,569 | 184,267 | 150,424 | |||||||||
| Notes: | ||
| (1) | Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe. | |
| (2) | Excludes royalty interests held by Pengrowth Corporation. | |
| NET PRESENT VALUES OF FUTURE NET REVENUE | ||||||||||||||||||||
| BEFORE INCOME TAXES | ||||||||||||||||||||
| DISCOUNTED AT (% per year) | ||||||||||||||||||||
| 0 | 5 | 10 | 15 | 20 | ||||||||||||||||
| RESERVES CATEGORY | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | |||||||||||||||
| Proved | ||||||||||||||||||||
| Developed Producing | 2,193.4 | 1,647.7 | 1,343.1 | 1,147.6 | 1,010.3 | |||||||||||||||
| Developed Non-Producing | 58.7 | 38.8 | 28.0 | 21.3 | 16.9 | |||||||||||||||
| Undeveloped | 510.7 | 339.5 | 233.0 | 162.5 | 113.6 | |||||||||||||||
| Total Proved | 2,762.8 | 2,026.0 | 1,604.1 | 1,331.5 | 1,140.8 | |||||||||||||||
| Probable | 765.4 | 448.8 | 306.6 | 227.1 | 176.6 | |||||||||||||||
| Total Proved Plus Probable | 3,528.2 | 2,474.8 | 1,910.7 | 1,558.6 | 1,317.4 | |||||||||||||||
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003
CONSTANT PRICES AND COSTS
| FUTURE | ||||||||||||||||||||||||
| NET | ||||||||||||||||||||||||
| REVENUE | ||||||||||||||||||||||||
| WELL | BEFORE | |||||||||||||||||||||||
| OPERATING | DEVELOPMENT | ABANDONMENT | INCOME | |||||||||||||||||||||
| REVENUE | ROYALTIES | COSTS | COSTS | COSTS | TAXES | |||||||||||||||||||
| RESERVES CATEGORY | ($M) | ($M) | ($M) | ($M) | ($M) | ($M) | ||||||||||||||||||
| Proved Reserves | 5,816,911 | 1,076,730 | 1,564,602 | 336,270 | 76,499 | 2,762,812 | ||||||||||||||||||
| Proved Plus Probable Reserves | 7,176,177 | 1,354,292 | 1,830,578 | 384,130 | 78,955 | 3,528,222 | ||||||||||||||||||
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003
CONSTANT PRICES AND COSTS
| FUTURE NET REVENUE BEFORE | ||||||
| INCOME TAXES | ||||||
| (discounted at 10% per year) | ||||||
| RESERVES CATEGORY | PRODUCTION GROUP | ($M) | ||||
| Proved Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 884,270 | ||||
| Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 713,853 | |||||
| Proved Plus Probable | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 1,056,697 | ||||
| Reserves | Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 847,872 | ||||
| Notes: |
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| (1) | NGL’s associated with the production of crude oil are included as a by-product. | |
| (2) | NGL’s associated with the production of natural gas are included as a by-product. |
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2003
FORECAST PRICES AND COSTS
| OIL AND GAS RESERVES | |||||||||||||||||||||||||||||||||||||
| LIGHT AND | NATURAL GAS | ||||||||||||||||||||||||||||||||||||
| MEDIUM OIL | NATURAL GAS | LIQUIDS | |||||||||||||||||||||||||||||||||||
| Pengrowth | Working | Pengrowth | Working | Pengrowth | Working | ||||||||||||||||||||||||||||||||
| Interest | Interest(2) | Net | Interest | Interest(2) | Net | Interest | Interest(2) | Net | |||||||||||||||||||||||||||||
| RESERVES CATEGORY | (mbbls) | (mbbls) | (mbbls) | (bcf) | (bcf) | (bcf) | (mbbls) | (mbbls) | (mbbls) | ||||||||||||||||||||||||||||
| Proved | |||||||||||||||||||||||||||||||||||||
| Developed Producing | 59,677 | 59,559 | 50,344 | 273 | 267 | 218 | 12,774 | 12,614 | 9,099 | ||||||||||||||||||||||||||||
| Developed Non-Producing | 494 | 492 | 414 | 12 | 11 | 9 | 237 | 231 | 189 | ||||||||||||||||||||||||||||
| Undeveloped | 17,867 | 17,853 | 15,910 | 54 | 52 | 44 | 1,628 | 1,577 | 1,221 | ||||||||||||||||||||||||||||
| Total Proved | 78,038 | 77,904 | 66,667 | 338 | 331 | 271 | 14,638 | 14,422 | 10,509 | ||||||||||||||||||||||||||||
| Probable | 19,322 | 19,288 | 16,506 | 75 | 71 | 57 | 3,611 | 3,531 | 2,629 | ||||||||||||||||||||||||||||
| Total Proved Plus Probable | 97,360 | 97,192 | 83,173 | 413 | 402 | 328 | 18,250 | 17,953 | 13,138 | ||||||||||||||||||||||||||||
| TOTAL OIL | ||||||||||||
| EQUIVALENT BASIS(1) | ||||||||||||
| Pengrowth | Working | |||||||||||
| Interest | Interest(2) | Net | ||||||||||
| RESERVES CATEGORY | (mboe) | (mboe) | (mboe) | |||||||||
| Proved | ||||||||||||
| Developed Producing | 117,937 | 116,717 | 95,760 | |||||||||
| Developed Non-Producing | 2,680 | 2,624 | 2,120 | |||||||||
| Undeveloped | 28,442 | 28,076 | 24,478 | |||||||||
| Total Proved | 149,060 | 147,417 | 122,357 | |||||||||
| Probable | 35,356 | 34,700 | 28,703 | |||||||||
| Total Proved Plus Probable | 184,416 | 182,118 | 151,060 | |||||||||
| Note: | ||
| (1) | Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe. | |
| (2) | Excludes royalty interests held by Pengrowth Corporation. | |
| NET PRESENT VALUES OF FUTURE NET REVENUE | ||||||||||||||||||||
| BEFORE INCOME TAXES | ||||||||||||||||||||
| DISCOUNTED AT (% per year) | ||||||||||||||||||||
| 0 | 5 | 10 | 15 | 20 | ||||||||||||||||
| RESERVES CATEGORY | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | |||||||||||||||
| Proved | ||||||||||||||||||||
| Developed Producing | 1,491.1 | 1,168.0 | 977.9 | 851.8 | 761.1 | |||||||||||||||
| Developed Non-Producing | 44.7 | 29.3 | 21.0 | 16.0 | 12.7 | |||||||||||||||
| Undeveloped | 338.3 | 213.4 | 136.4 | 85.9 | 51.0 | |||||||||||||||
| Total Proved | 1,874.1 | 1,410.7 | 1,135.4 | 953.6 | 824.8 | |||||||||||||||
| Probable | 575.7 | 336.2 | 229.2 | 169.9 | 132.3 | |||||||||||||||
| Total Proved Plus Probable | 2,449.7 | 1,746.9 | 1,364.6 | 1,123.5 | 957.2 | |||||||||||||||
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TOTAL OF FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003
FORECAST PRICES AND COSTS
| FUTURE | ||||||||||||||||||||||||
| NET | ||||||||||||||||||||||||
| REVENUE | ||||||||||||||||||||||||
| WELL | BEFORE | |||||||||||||||||||||||
| OPERATING | DEVELOPMENT | ABANDONMENT | INCOME | |||||||||||||||||||||
| RESERVES | REVENUE | ROYALTIES | COSTS | COSTS | COSTS | TAXES | ||||||||||||||||||
| CATEGORY | ($M) | ($M) | ($M) | ($M) | ($M) | ($M) | ||||||||||||||||||
| Proved Reserves | 4,823,665 | 800,685 | 1,710,096 | 345,920 | 92,906 | 1,874,058 | ||||||||||||||||||
| Proved Plus Probable Reserves | 6,049,709 | 1,016,693 | 2,085,052 | 398,309 | 99,918 | 2,449,737 | ||||||||||||||||||
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003
FORECAST PRICES AND COSTS
| FUTURE NET REVENUE BEFORE | ||||||
| INCOME TAXES | ||||||
| (discounted at 10% per year) | ||||||
| RESERVES CATEGORY | PRODUCTION GROUP | ($M) | ||||
| Proved Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 590,512 | ||||
| Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 539,016 | |||||
| Proved Plus Probable Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 713,320 | ||||
| Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 645,201 | |||||
| Notes: | ||
| (1) | NGL’s associated with the production of crude oil are included as a by-product. | |
| (2) | NGL’s associated with the production of natural gas are included as a by-product. | |
SUMMARY OF PRICING ASSUMPTIONS
as of December 31, 2003
CONSTANT PRICES AND COSTS
| EXCHANGE | ||||||||||||||||||||||||||||||||
| OIL | NATURAL GAS | NATURAL GAS LIQUIDS(1) | RATE | |||||||||||||||||||||||||||||
| WTI Cushing | Edmonton Par Price | Cromer Medium | AECO Gas | Butane | ||||||||||||||||||||||||||||
| Oklahoma | 400 API | 29.30 API | Price | Propane | Field Gate | Pentanes Plus | ||||||||||||||||||||||||||
| Year(2) | ($US/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/mmbtu) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($US/Cdn) | ||||||||||||||||||||||||
2004(3) | 32.52 | 40.81 | 34.81 | 6.09 | 29.81 | 31.81 | 41.31 | 0.7738 | ||||||||||||||||||||||||
| Notes: | ||
| (1) | At Edmonton. | |
| (2) | Information provided as at December 31, 2003. | |
| (3) | This forecast represents the constant price forecast used by GLJ. | |
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SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2003
FORECAST PRICES AND COSTS
| INFLATION | EXCHANGE | |||||||||||||||||||||||||||||||||||
| OIL | NATURAL GAS | NATURAL GAS LIQUIDS(1) | RATES(2) | RATE(3) | ||||||||||||||||||||||||||||||||
| WTI Cushing | Edmonton Par Price | Cromer Medium | AECO Gas | Butane | ||||||||||||||||||||||||||||||||
| Oklahoma | 400 API | 29.30 API | Price | Propane | Field Gate | Pentanes Plus | ||||||||||||||||||||||||||||||
| Year | ($US/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/mmbtu) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | (%/Year) | ($US/Cdn) | |||||||||||||||||||||||||||
| 2004 | 29.00 | 37.75 | 31.75 | 5.85 | 26.75 | 28.75 | 38.25 | 1.5 | 0.75 | |||||||||||||||||||||||||||
| 2005 | 26.00 | 33.75 | 28.75 | 5.15 | 21.75 | 23.75 | 34.25 | 1.5 | 0.75 | |||||||||||||||||||||||||||
| 2006 | 25.00 | 32.50 | 28.50 | 5.00 | 20.50 | 22.50 | 33.00 | 1.5 | 0.75 | |||||||||||||||||||||||||||
| 2007 | 25.00 | 32.50 | 28.50 | 5.00 | 20.50 | 22.50 | 33.00 | 1.5 | 0.75 | |||||||||||||||||||||||||||
| 2008 to 2014 | 25.00 | 32.50 | 28.50 | 5.00 | 20.50 | 22.50 | 33.00 | 1.5 | 0.75 | |||||||||||||||||||||||||||
| Thereafter | +1.5 | % | +1.5 | % | +1.5 | % | +1.5 | % | +1.5 | % | +1.5 | % | +1.5 | % | +1.5 | 0.75 | ||||||||||||||||||||
| Notes: | ||
| (1) | At Edmonton. | |
| (2) | Inflation rates for forecasting prices and costs. | |
| (3) | The exchange rates used to generate the benchmark reference prices in this table. | |
RECONCILIATION OF
NET RESERVES BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
| LIGHT AND MEDIUM OIL | NATURAL GAS | |||||||||||||||||||||||
| Net Proved | Net Proved | |||||||||||||||||||||||
| Net Proved | Net Probable | Plus Probable | Net Proved | Net Probable | Plus Probable | |||||||||||||||||||
| FACTORS | (mbbls) | (mbbls) | (mbbls) | (mmcf) | (mmcf) | (mmcf) | ||||||||||||||||||
December 31, 2002 | 76,129 | 13,846 | 89,975 | 340,900 | 58,800 | 399,700 | ||||||||||||||||||
| Extensions | 1 | (1 | ) | — | 3,100 | 2,000 | 5,100 | |||||||||||||||||
| Improved Recovery | — | — | — | — | — | — | ||||||||||||||||||
| Technical Revisions | (2,843 | ) | 2,648 | (195 | ) | (37,900 | ) | (3,300 | ) | (41,200 | ) | |||||||||||||
| Discoveries | — | — | — | 100 | (100 | ) | — | |||||||||||||||||
| Acquisitions | 274 | 76 | 350 | 700 | 100 | 800 | ||||||||||||||||||
| Dispositions | (239 | ) | (63 | ) | (302 | ) | (600 | ) | (100 | ) | (700 | ) | ||||||||||||
| Economic Factors | — | — | — | — | — | — | ||||||||||||||||||
| Production | (6,655 | ) | — | (6,655 | ) | (35,200 | ) | — | (35,200 | ) | ||||||||||||||
December 31, 2003 | 66,667 | 16,506 | 83,173 | 271,100 | 57,400 | 328,500 | ||||||||||||||||||
[Continued from above table, first column(s) repeated]
| NATURAL GAS LIQUIDS | TOTAL OIL EQUIVALENT BASIS(1) | |||||||||||||||||||||||
| Net Proved | Net Proved | |||||||||||||||||||||||
| Net Proved | Net Probable | Plus Probable | Net Proved | Net Probable | Plus Probable | |||||||||||||||||||
| (mbbls) | (mbbls) | (mbbls) | (mboe) | (mboe) | (mboe) | |||||||||||||||||||
December 31, 2002 | 15,150 | 2,708 | 17,858 | 148,096 | 26,354 | 174,450 | ||||||||||||||||||
| Extensions | 74 | 54 | 128 | 592 | 386 | 978 | ||||||||||||||||||
| Improved Recovery | — | — | — | — | — | — | ||||||||||||||||||
| Technical Revisions | (3,045 | ) | (141 | ) | (3,186 | ) | (12,206 | ) | 1,957 | (10,247 | ) | |||||||||||||
| Discoveries | — | — | — | 17 | (17 | ) | — | |||||||||||||||||
| Acquisitions | 36 | 8 | 44 | 427 | 101 | 527 | ||||||||||||||||||
| Dispositions | (20 | ) | — | (20 | ) | (359 | ) | (80 | ) | (439 | ) | |||||||||||||
| Economic Factors | — | — | — | — | — | — | ||||||||||||||||||
| Production | (1,686 | ) | — | (1,686 | ) | (14,208 | ) | — | (14,208 | ) | ||||||||||||||
December 31, 2003 | 10,509 | 2,629 | 13,138 | 122,359 | 28,702 | 151,061 | ||||||||||||||||||
| Note: | ||
| (1) | Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe. | |
At year end 2003, Pengrowth Corporation’s remaining recoverable Total Proved Plus Probable Reserves were 184.4 mmboe as compared to 214.8 mmboe of established reserves reported at year end 2002. Although not directly comparable due to a change in reserve definitions under NI 51-101, the Total Proved Plus Probable Reserves are similar to Pengrowth’s previously reported “established” reserves which were defined as proved plus 50% of probable reserves under the old reserve definitions.
The following additional GLJ reserves reconciliation is presented for year-end December 31, 2003.
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RECONCILIATION OF RESERVES
ON TOTAL EQUIVALENT BASIS
FORECAST PRICES AND COSTS
| Proved | Proved Plus | |||||||||||
| Producing Reserves | Proved Reserves | Probable Reserves | ||||||||||
| (mboe)(1)(2) | (mboe)(1)(2) | (mboe)(1)(2) | ||||||||||
December 31, 2002(3) | 130,868 | 181,381 | 214,844 | (4) | ||||||||
| Exploration and Development | 4,190 | 2,720 | 2,710 | |||||||||
Revisions(5) | 1,090 | (17,110 | ) | (15,267 | ) | |||||||
| Acquisitions | 240 | 490 | 620 | |||||||||
| Dispositions | (410 | ) | (420 | ) | (510 | ) | ||||||
| Production | (17,897 | ) | (17,897 | ) | (17,897 | ) | ||||||
December 31, 2003 | 118,081 | 149,164 | 184,470 | |||||||||
| Notes: | ||
| (1) | Pengrowth’s working interest share before royalties. | |
| (2) | Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe. | |
| (3) | National Policy Statement 2-B reserves definitions. | |
| (4) | “Established” (proved reserves and one-half probable reserves) reserves as at December 31, 2002 based on National Policy Statement 2-B reserves definitions. | |
| (5) | Revisions reflect both reservoir performance and the effect of the change in reserves definitions under NI 51-101. | |
Significant factors on the reserves reconciliation were as follows:
| • | GLJ reduced estimates of sales gas reserves attributed to Pengrowth Corporation’s 8.4% working interest in the Sable Offshore Energy Project (“SOEP”) determined at project startup by 50 bcf from 176 bcf to 126 bcf consistent with the reduction to SOEP reserves announced by Shell Canada Resources Limited on January 29, 2004. The adjustments were primarily due to the removal of the Glenelg field from current development plans, the exclusion of an undrilled fault block at North Triumph and poorer than anticipated performance at the Venture field. | |||
| • | Revisions to Proved Reserves for Pengrowth Corporation’s overall oil and gas property portfolio are 17.1 mmboes or approximately 9.3% of Pengrowth Corporation’s Proved Reserves. Effective December 31, 2003, SOEP represented approximately 10% of Pengrowth’s total Proved Reserves. | |||
| • | Revisions to Total Proved Plus Probable Reserves (formerly “established reserves” reported by GLJ as at December 31, 2002) were 15.3 mmboes or 7.1%, approximately 85% of which can be attributed to reductions in reserves for Pengrowth Corporation’s SOEP interest. | |||
RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR
PROVED RESERVES
CONSTANT PRICES AND COSTS
| Period and Factor | Before Tax 2003 ($M) | |||
Estimated Net Present Value at Beginning of Year | 1,941,700 | |||
Oil and Gas Sales During the Period Net of Production Costs and Royalties(1) | (395,000 | ) | ||
Net Change due to Prices and Royalties Related to Forecast Production(2) | (115,000 | ) | ||
Change in Development Costs During the Period(3) | 85,700 | |||
Change in Forecast Development Costs(4) | — | |||
Change Resulting from Extensions and Improved Recovery(5) | 7,200 | |||
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| Period and Factor | Before Tax 2003 ($M) | |||
Net Change Resulting from Discoveries(5) | 300 | |||
Change Resulting from Acquisitions of Reserves(5) | 5,400 | |||
Change Resulting from Dispositions of Reserves(5) | (4,500 | ) | ||
Accretion of Discount(6) | 194,170 | |||
Net Change in Income Taxes(7) | — | |||
Change Resulting from Technical Reserves Revisions(8) | (133,900 | ) | ||
| All Other Changes | 18,000 | |||
Estimated Net Present Value at End of Year | 1,604,070 | |||
| Notes: | ||
| (1) | Net of income taxes and excluding general and administrative expenses. | |
| (2) | The impact of changes in prices and other economic factors on future net revenue. | |
| (3) | Actual capital expenditures relating to the exploration, development and production of oil and gas reserves. | |
| (4) | The change in forecast development costs. | |
| (5) | End of period net present value of the related reserves. | |
| (6) | Estimated as 10% of the beginning of period net present value. | |
| (7) | The difference between forecast income taxes at beginning of period and actual taxes for the period plus forecast income taxes at the end of period. | |
| (8) | Changes due to the implementation of new reserve definitions under NI 51-101 and reductions in proved reserves primarily due to a reserves adjustment for Pengrowth Corporation’s 8.4% working interest in SOEP. | |
Additional Information Relating to Reserves Data
Undeveloped Reserves
Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.
Proved and probable undeveloped reserves have been estimated in accordance with procedures and standards contained in the COGE Handbook. In general, undeveloped reserves are scheduled to be developed within the next two years. Much of the remaining capital scheduled beyond two years is related to the Sable Island Offshore and Weyburn carbon dioxide projects, which have staged development plans.
Proved Undeveloped Reserves
Pengrowth Corporation’s Proved Undeveloped Reserves comprise roughly 20% of the total Proved Reserves on a barrel of oil equivalency basis. The 24.5 mmboe of Proved Undeveloped Reserves (net of royalties) assigned to Pengrowth Corporation by GLJ meets the current accepted guidelines as stated in National Instrument 51-101 —Standards of Disclosure for Oil and Gas Activities. In general, Proved Undeveloped Reserves were assigned to certain properties because capital commitments have been made to convert the Undeveloped Reserves to Proved Producing Reserves. Proved Undeveloped Reserves have been primarily assigned for future miscible flood expansion and development drilling.
The Judy Creek Units hold roughly 27% of the Proved Undeveloped Reserves. Miscible injection has resulted in an overall incremental recovery of between five and seven percent of the original oil in place in this area and has been in use since 1985. Miscible flood expansion is an on going program which is limited by the availability of injectant materials and is budgeted to continue through to 2008. Similarly, at Swan Hills miscible flood expansion as well as some infill drilling accounts for another 17% of Pengrowth’s Proved Undeveloped Reserves assignments. The Swan Hills Unit Reserves have a 50 year reserve life. The incremental recovery is well documented and is forecasted to continue until 2014. In the Weyburn Unit, an additional 14% of the Proved Undeveloped Reserves assignment reflects the capital allocated to the CO2 miscible flood. Working interest partners are committed to a 15 year supply of CO2 to further develop the flood area from the existing 32 patterns to full development with 75 patterns.
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SOEP has 17% of the Pengrowth’s Proved Undeveloped Reserves to reflect capital committed to future drilling. The 2004 budget has allocated capital for drilling three new wells in South Venture along with the construction of the South Venture platform. Shallow gas infill programs at Monogram (154 wells) and Tilley (100 wells) will be underway in 2004. Roughly 8% of the total Proved Undeveloped Reserves can be attributed to these projects. The Dunvegan Unit has 4% of the Proved Undeveloped Reserves assignments that reflect an on-going successful recompletion and drilling program.
Future Development Costs
The following table outlines development costs deducted in the estimation of future net revenue for each of the next five financial years and in total, undiscounted and using a discount rate of 10% per annum.
| 2004 | 2005 | 2006 | 2007 | 2008 | Remainder | Total | Total (discounted | |||||||||||||||||||||||||
| (undiscounted) | (undiscounted) | (undiscounted) | (undiscounted) | (undiscounted) | (undiscounted) | (undiscounted) | at 10%) | |||||||||||||||||||||||||
| RESERVE CATEGORY | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ||||||||||||||||||||||||
| Proved Reserves (Constant Prices and Costs) | 125.2 | 67.5 | 51.8 | 19.4 | 15.9 | 56.5 | 336.3 | 267.9 | ||||||||||||||||||||||||
| Proved Reserves (Forecast Prices and Costs) | 125.2 | 68.4 | 53.2 | 20.2 | 16.8 | 62.1 | 345.9 | 272.8 | ||||||||||||||||||||||||
| Proved & Probable Reserves (Forecast Prices and Costs) | 131.2 | 82.4 | 63.5 | 24.4 | 19.7 | 77.1 | 398.3 | 309.9 | ||||||||||||||||||||||||
Commencing with the January 15, 2003 distribution to unitholders, approximately 10% of cash available for distribution has been withheld to fund capital expenditures.
Other Oil And Gas Information
Oil and Gas Wells
As at December 31, 2003, Pengrowth had an interest in 3,585 gross (1,049 net) producing oil and natural gas wells and 542 gross (268 net) inactive wells.
| PRODUCING | NON-PRODUCING | |||||||||||||||
| Gross | Net | Gross | Net | |||||||||||||
| Crude Oil Wells | ||||||||||||||||
| Alberta | 875 | 312 | 249 | 116 | ||||||||||||
| British Columbia | 148 | 103 | 44 | 39 | ||||||||||||
| Saskatchewan | 749 | 89 | 61 | 6 | ||||||||||||
| Nova Scotia | 0 | 0 | 0 | 0 | ||||||||||||
| Natural Gas Wells | ||||||||||||||||
| Alberta | 1660 | 469 | 81 | 19 | ||||||||||||
| British Columbia | 139 | 75 | 59 | 44 | ||||||||||||
| Saskatchewan | 0 | 0 | 0 | 0 | ||||||||||||
| Nova Scotia | 14 | 1 | 0 | 0 | ||||||||||||
| Other | ||||||||||||||||
British Columbia(1) | 0 | 0 | 48 | 44 | ||||||||||||
| Total | 3585 | 1049 | 542 | 268 | ||||||||||||
| Note: | ||
| (1) | Pengrowth cannot classify these wells as either oil or gas. | |
Properties with No Attributed Reserves
The following table sets forth the gross and net acres of unproved properties held by Pengrowth and the net area of unproved property for which Pengrowth expects its rights to explore, develop and exploit to expire during the next year.
| UNPROVED PROPERTIES | ||||||||||||
| (acres) | ||||||||||||
| LOCATION | Gross | Net | Net Area to Expire | |||||||||
| Alberta | 65,586 | 22,955 | 4,590 | |||||||||
| British Columbia | 605,312 | 292,536 | 58,500 | |||||||||
| Saskatchewan | 1,393 | 201 | — | |||||||||
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| UNPROVED PROPERTIES | ||||||||||||
| (acres) | ||||||||||||
| LOCATION | Gross | Net | Net Area to Expire | |||||||||
| Nova Scotia | — | — | — | |||||||||
| Other | — | — | — | |||||||||
TOTAL | 672,291 | 315,692 | 63,090 | |||||||||
Unproved Properties
The expiring acreage in Alberta will be held based on current activity which is focused on exploitation of up-hole potential in existing wells.
The British Columbia properties are primarily “winter access only” properties. Three wells were drilled in January 2004. There is a concerted effort being made to farmout the remaining properties that are scheduled to expire. The properties remaining will be placed in sale packages when all other opportunities have been exhausted.
Forward Contracts
Pengrowth sells forward a portion of its future production through a combination of fixed price sales contracts with customers and commodity swap agreements with financial counterparties. Pengrowth has hedged a total of 17,000 mmbtupd of SOEP natural gas using financial swaps for the remainder of 2004 at an average price of $7.11 per mmbtu.
In 2005, Pengrowth has hedged a total of 6000 mmbtupd of SOEP natural gas at an average price of $8.86 per mmbtu. Pengrowth has an additional 3500 giga joules per day of AECO gas hedged for 2004 at an average price of $7.17 per giga joule.
Pengrowth has currently hedged 10,500 blpd of crude oil for the remainder of 2004 at an average price of $38.78 per bbl including foreign exchange risk. In 2005, Pengrowth has hedged a total of 2,000 bblpd of crude oil at an average price of $48.60 per bbl.
From February 1, 2004 to December 31, 2004 Pengrowth has hedged 5 mega watts of power at an average price of $53 per mega watt hour.
Abandonment & Reclamation Costs
The total future abandonment and reclamation costs are estimated by management based on Pengrowth Corporation’s working interest in its wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities, and the estimated costs to be incurred in future periods. The downhole abandonment costs are included in the GLJ Report and therefore are included in the estimate of future net revenue. All other abandonment and reclamation costs are not reflected in the estimate of future net revenue.
Pengrowth has estimated the net present value (discounted 10% per annum) of its total asset retirement obligations to be $84 million as at December 31, 2003, based on a total future liability of $352 million. These costs are anticipated to be made over 51 years with the majority of the costs incurred between 2014 and 2040.
Pengrowth anticipates to incur abandonment costs on a total of 503 net oil wells, 545 net gas wells and 239 net inactive wells.
The following table summarizes Pengrowth’s total asset retirement obligation:
| Future Reclamation, Remediation, Dismantling & Abandonment Costs | ||||||||||||||||||||
| 2004 | 2005 | 2006 | Remainder | Total | ||||||||||||||||
| ($M) | ($M) | ($M) | ($M) | ($M) | ||||||||||||||||
| Total Reclamation, Remediation & Dismantling | 5,329 | 6,560 | 6,858 | 312,236 | 330,983 | |||||||||||||||
| Well Abandonment | 641 | 671 | 638 | 18,755 | 20,705 | |||||||||||||||
| Total | 5,970 | 7,231 | 7,496 | 330,991 | 351,688 | |||||||||||||||
| Discounted at 10% | 5,692 | 6,268 | 5,906 | 66,374 | 84,240 | |||||||||||||||
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Tax Horizon
In determining its taxable income, Pengrowth Corporation deducts royalty payments to unitholders and, historically, this has been sufficient to reduce taxable income to nil. The recent change to Pengrowth’s distribution approach, whereby approximately 10 percent of funds available for distribution are withheld to fund future capital expenditures, could result in taxable income in Pengrowth Corporation in the future. However, there are at present sufficient tax pools available in Pengrowth Corporation to offset the expected level of income to be retained. As a result, our after tax future net revenues from our reserves are the same as our before tax future net revenues from our reserves.
Costs Incurred
The following table outlines property acquisition, exploration and development costs incurred during the financial year ended December 31, 2003.
| NATURE OF COST | AMOUNT ($MM) | |||
| Acquisition Costs | 123.0 | |||
| Proved | — | (1) | ||
| Unproved | — | (1) | ||
| Exploration Costs | — | |||
| Development Costs | 85.7 | |||
| Total | 208.7 | |||
| Note: | ||
| (1) | The acquisition costs reflect the amount paid by Pengrowth to acquire a working interest in the SOEP natural gas processing facilities downstream of the Thebaud Central Processing Platform and the SOEP offshore platforms and associated sub-sea field gathering lines from Emera. This purchase results in a savings in operating costs and does not increase proved and unproved reserve values. | |
Development Activities
The following table summarizes the results of development activities during the financial year ended December 31, 2003.
| GROSS | NET | |||||||
| Development Wells | ||||||||
| Gas | 138.0 | 61.7 | ||||||
| Oil | 29.0 | 8.3 | ||||||
| Service | 4.0 | 3.9 | ||||||
| Dry | 9.0 | 3.8 | ||||||
| Total Wells | 180.0 | 77.7 | ||||||
Production
Production Estimates
The following tables summarize the volume of production estimated for the year ended December 31, 2004 using constant and forecast prices and costs.
| ESTIMATED PRODUCTION | ||||||||
| Total Proved | Proved Plus Probable | |||||||
| Constant Prices and Costs | Forecast Prices and Costs | |||||||
| Light and Medium Crude Oil (bblpd) | 21,597 | 22,086 | ||||||
| Natural Gas (mcfpd) | 111,693 | 116,882 | ||||||
| Natural Gas Liquids (bblpd) | 5,401 | 5,657 | ||||||
Production History
The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting operating netbacks of Pengrowth for the periods indicated below:
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| QUARTER ENDED | |||||||||||||||||
| March 31, 2003 | June 30, 2003 | September 30, 2003 | December 31, 2003 | ||||||||||||||
Crude Oil and NGLS(1) | |||||||||||||||||
Average Daily Oil Production(2) (bblpd) | 24,807 | 23,530 | 22,852 | 22,193 | |||||||||||||
Average Daily NGL Production(2) (bblpd) | 5,952 | 5,390 | 5,641 | 5,907 | |||||||||||||
| Sales Price (net of hedging gains/losses) ($/bbl) | 44.11 | 38.83 | 37.75 | 37.53 | |||||||||||||
| Processing and other income ($/bbl) | 0.76 | 0.12 | 0.70 | 0.54 | |||||||||||||
| Royalties ($/bbl) | (8.42 | ) | (7.62 | ) | (7.26 | ) | (4.78 | ) | |||||||||
| Amortization of injectants ($/bbl) | (3.56 | ) | (3.43 | ) | (2.90 | ) | (2.33 | ) | |||||||||
| Production Costs ($/bbl) | (8.56 | ) | (8.01 | ) | (8.52 | ) | (9.61 | ) | |||||||||
| Operating Netback ($/bbl) | 24.33 | 19.89 | 19.77 | 21.35 | |||||||||||||
Natural Gas(1) | |||||||||||||||||
Average Daily Natural Gas Production(2) (mcfpd) | 120,402 | 119,519 | 122,140 | 117,315 | |||||||||||||
| Sales Price (net of hedging gains/losses) ($/mcfpd) | 7.63 | 6.20 | 5.67 | 5.36 | |||||||||||||
| Processing and other income ($/mcfpd) | 0.18 | 0.19 | 0.16 | 0.17 | |||||||||||||
| Royalties ($/mcfpd) | (1.38 | ) | (1.33 | ) | (1.02 | ) | (1.02 | ) | |||||||||
| Production Costs ($/mcfpd) | (1.46 | ) | (1.25 | ) | (1.20 | ) | (1.32 | ) | |||||||||
| Operating Netback ($/mcfpd) | 4.97 | 3.81 | 3.61 | 3.19 | |||||||||||||
| Notes: | ||
| (1) | Determined based upon the principal product type attributable to each well. | |
| (2) | Before the deduction of royalties. | |
| QUARTER ENDED | |||||||||||||||||
| March 31, 2003 | June 30, 2003 | September 30, 2003 | December 31, 2003 | ||||||||||||||
Barrels of Oil Equivalent(1) | |||||||||||||||||
Average Daily Production(2) (boepd) | 50,827 | 48,839 | 48,850 | 47,653 | |||||||||||||
| Sales Price (net of hedging gains/losses) ($/boe) | 44.33 | 37.63 | 35.76 | 34.69 | |||||||||||||
| Processing and other income ($/boe) | 0.65 | 0.48 | 0.62 | 0.63 | |||||||||||||
| Royalties ($/boe) | (7.69 | ) | (7.17 | ) | (6.17 | ) | (4.60 | ) | |||||||||
| Amortization of injectants ($/boe) | (2.16 | ) | (2.03 | ) | (1.69 | ) | (1.38 | ) | |||||||||
| Production Costs ($/boe) | (8.63 | ) | (7.80 | ) | (7.98 | ) | (8.91 | ) | |||||||||
| Operating Netback ($/boe) | 26.50 | 21.11 | 20.54 | 20.43 | |||||||||||||
| Notes: | ||
| (1) | Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe. | |
| (2) | Before the deduction of royalties. | |
Production History
The annual and average daily production of crude oil, natural gas and natural gas liquids of Pengrowth Corporation is set out in the following table:
| Crude Oil | Natural Gas | Natural Gas Liquids | ||||||||||||||||||||||||||
| Annual | Average Daily | Annual | Average Daily | Annual | Average Daily | Average Daily Total | ||||||||||||||||||||||
| Year ended | Production(2) | Production(2) | Production(2) | Production(2) | Production(2) | Production(2) | Production(1)(2) | |||||||||||||||||||||
| 12 Months To | (mbbls) | (bblpd) | (mmcf) | (mcfpd) | (mbbls) | (bblpd) | (boepd) | |||||||||||||||||||||
| December 31, 1997 | 2,792 | 7,650 | 18,744 | 51,355 | 677 | 1,856 | 18,140 | |||||||||||||||||||||
| December 31, 1998 | 6,094 | 16,695 | 21,063 | 57,707 | 1,220 | 3,342 | 29,741 | |||||||||||||||||||||
| December 31, 1999 | 6,413 | 17,570 | 22,445 | 61,494 | 1,433 | 3,927 | 31,821 | |||||||||||||||||||||
| December 31, 2000 | 6,441 | 17,599 | 25,656 | 70,098 | 1,539 | 4,205 | 33,581 | |||||||||||||||||||||
| December 31, 2001 | 7,200 | 19,726 | 33,494 | 91,764 | 1,919 | 5,258 | 40,320 | |||||||||||||||||||||
| December 31, 2002 | 7,269 | 19,914 | 40,775 | 111,713 | 1,917 | 5,252 | 43,785 | |||||||||||||||||||||
| December 31, 2003 | 8,518 | 23,337 | 43,742 | 119,842 | 2,089 | 5,722 | 49,033 | |||||||||||||||||||||
| Note: | ||
| (1) | Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe. | |
| (2) | Before the deduction of royalties. | |
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Replacement of Properties
In the event that Pengrowth Corporation determines that the sale of any of its interests in properties, and the release of the royalty therefrom, would be in the best interest of the unitholders, the royalty indenture permits it to make sales without the requirement of approval of the unitholders, provided that the aggregate properties sold in any given year total less than 25% of the assets of Pengrowth Corporation, determined as at the date of disposition of the properties based upon an independent engineering appraisal. Any sale exceeding this threshold must be approved by an extraordinary resolution of the unitholders.
In connection with any sale of properties, Pengrowth Corporation will also be required to consider whether the net proceeds of the sale should be distributed or reinvested to purchase replacement properties (the “Replacement Properties”). If the proceeds of disposition are not reinvested in the purchase of Replacement Properties within the same calendar year then these proceeds are allocated to the holders of royalty units, provided that such rights are subordinate to the rights of the lenders to Pengrowth Corporation under its credit facility and operating time of credit.
Borrowing
Pursuant to the royalty indenture, Pengrowth Corporation is permitted to borrow funds to finance the purchase of properties or for capital expenditures, to incur take or pay obligations and other burdens and encumbrances in respect of the properties, and to grant security on the properties in priority to the royalty to secure the borrowing of such funds. Repayment of debt shall be scheduled so as to minimize, to the extent possible, income tax payable by Pengrowth Corporation. Debt service charges (to the extent that they exceed certain revenues of Pengrowth Corporation) and taxes payable by Pengrowth Corporation will be deducted in computing royalty income.
In April 2003, Pengrowth closed a US$200 million private placement of senior unsecured notes to a group of U.S. institutional investors. The notes are in two tranches, one of US$150 million 4.93% senior notes due April 23, 2010 and one of US$50 million 5.47% senior notes due 2013. In addition, Pengrowth has a $200 million revolving credit facility syndicated among eight financial institutions that is extendible on June 18, 2004 for a 364 day revolving period or a two year amortization term. These arrangements replace a single $540 million revolving credit facility that had been in place on December 31, 2002. Pengrowth also has a $35 million demand operating line of credit.
TRUST UNITS
The Trust Indenture
Trust units are issued under the terms of a trust indenture between Pengrowth Corporation and Computershare, as trustee. A maximum of 500,000,000 trust units may be created and issued pursuant to the trust indenture, of which 123,873,651 trust units were outstanding on December 31, 2003. Each trust unit represents a fractional undivided beneficial interest in Pengrowth Trust.
The trust indenture, among other things, provides for the establishment of Pengrowth Trust, the issue of trust units, the permitted investments of Pengrowth Trust, the procedures respecting distributions to unitholders, the appointment and removal of Computershare as trustee, Computershare’s authority and restrictions thereon, the calling of meetings of unitholders, the conduct of business at such meetings, notice provisions, the form of trust unit certificates and the termination of Pengrowth Trust. The trust indenture may be amended from time to time. Most amendments to the trust indenture, including the early termination of Pengrowth Trust and the sale or transfer of the property of Pengrowth Trust as an entirety or substantially as an entirety, require approval by an extraordinary resolution of the unitholders. An extraordinary resolution of the unitholders requires the approval of not less than 66 2/3% of the votes cast by unitholders at a meeting of unitholders held in accordance with the trust indenture at which two or more holders of at least 5% of the aggregate number of trust units then outstanding are represented. Computershare, as trustee, is permitted to amend the trust indenture without the consent or approval of the unitholders for certain purposes, including: (i) ensuring that Pengrowth Trust complies with applicable laws or government requirements, including satisfaction of certain provisions of theIncome Tax Act(Canada); (ii) ensuring that additional protection is provided for the interests of unitholders as Computershare may consider expedient; and (iii) making typographical or other non-substantive changes that are not adverse to the interests of Computershare or unitholders.
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The Trustee
Computershare, as trustee, is generally empowered by the trust indenture to exercise any and all rights and powers that could be exercised by the owner of the assets of Pengrowth Trust. Computershare’s specific responsibilities include, but are not limited to, the following: (i) reviewing and accepting subscriptions for trust units and issuing trust units subscribed for; (ii) subscribing for royalty units; (iii) issuing trust units in exchange for royalty units tendered to it for exchange; and (iv) maintaining records and providing timely reports to unitholders. Computershare is authorized to delegate its powers and duties as trustee except as prohibited by law.
Computershare, as trustee, must exercise its powers and carry out its functions under the trust indenture honestly, in good faith and in the best interests of Pengrowth Trust and the unitholders, and must exercise that degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. Computershare is not required to devote its entire time to the business and affairs of Pengrowth Trust.
Computershare, as trustee, shall be reappointed or replaced every two years as may be determined by a majority of the votes cast at an annual meeting of the unitholders. Computershare may resign upon 60 days notice to Pengrowth Corporation. Computershare may be removed by extraordinary resolution of the unitholders or by Pengrowth Corporation in certain specific circumstances. Such resignation or removal shall become effective upon the acceptance of appointment by a successor.
Redemption Right
Trust units are redeemable by Computershare, as trustee, at the request of a unitholder when properly endorsed for transfer and when accompanied by a duly completed and properly executed notice requesting redemption. The redemption right permits unitholders in the aggregate to redeem trust units for maximum proceeds of $25,000 in any calendar month; provided that such limitation may be waived at the discretion of the Board of Directors. The redemption price is the lesser of: (i) 95% of the market price of the trust units on the principal market on which the trust units are quoted for trading during the 10 day trading period commencing immediately after the date on which the trust units are surrendered for redemption; and (ii) the closing market price on the principal market on which the trust units are quoted for trading on the date that the trust units are surrendered for redemption.
Voting at Meetings of Pengrowth Trust
Meetings of unitholders may be called on 21 days notice and may be called at any time by Computershare, as trustee, or upon written request of unitholders holding in the aggregate not less than 5% of the trust units, and shall be called by Computershare and held annually. All activities necessary to organize any such meeting will be undertaken by Pengrowth Corporation on behalf of Computershare. At all meetings of the unitholders, each holder is entitled to one vote in respect of each trust unit held. Unitholders may attend and vote at all meetings of the unitholders either in person or by proxy and a proxy holder need not be a unitholder. Two persons present in person either holding personally or representing as proxies at least 5% of the outstanding trust units constitute a quorum for the transaction of business at all such meetings. Except as otherwise provided in the trust indenture, matters requiring the approval of the unitholders must be approved by extraordinary resolution.
Unitholders are entitled to pass resolutions that will bind Computershare, as trustee, with respect to a limited list of matters, including but, not limited to, the following: (i) the removal or appointment of Computershare as trustee; (ii) the removal or appointment of the auditor of Pengrowth Trust; (iii) the amendment of the trust indenture; (iv) the approval of subdivisions or consolidations of trust units; (v) the sale of the assets of Pengrowth Trust as an entirety or substantially as an entirety; and (vi) termination of Pengrowth Trust.
Unitholders can also consider the appointment of an inspector to investigate whether Computershare has performed its duties arising under the trust indenture. Such an inspector shall be appointed if a resolution approving the appointment of such inspector is passed by a majority of the votes duly cast at a meeting held for that purpose.
Voting at Meetings of Pengrowth Corporation
The unitholders, along with holders of royalty units other than Computershare, as trustee, are entitled to voting rights at meetings of shareholders of Pengrowth Corporation on the basis of one vote for each trust unit (or royalty Unit) held.
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Termination of Pengrowth Trust
The unitholders may vote to terminate Pengrowth Trust at any meeting of the unitholders, subject to the following:
| (i) | a vote may be held only if requested in writing by the holders of not less than 25% of the trust units, or if the trust units have become ineligible for investment by RRSPs, RRIFs, RESPs and DPSPs; |
| (ii) | the termination must be approved by extraordinary resolution of the unitholders; and |
| (iii) | a quorum representing 5% of the issued and outstanding trust units must be present or represented by proxy at the meeting at which the vote is taken. |
If the unitholders approve termination, Computershare, as trustee, will sell the assets of Pengrowth Trust, discharge all known liabilities and obligations, and distribute the remaining assets to the unitholders. Computershare will distribute directly to the unitholders any assets which Computershare is unable to sell by the date set for termination.
Unitholder Limited Liability
The trust indenture, provides that no unitholder will be subject to any personal liability in connection with Pengrowth Trust or its obligations and affairs, and the satisfaction of claims of any nature arising out of or in connection therewith is only to be made out of Pengrowth Trust’s assets. Additionally, the trust indenture states that no unitholder is liable to indemnify or reimburse Computershare for any liabilities incurred by Computershare with respect to any taxes payable by or liabilities incurred by Pengrowth Trust or Computershare, and all such liabilities will be enforceable only against, and will be satisfied only out of, Pengrowth Trust’s assets. It is intended that the operations of Pengrowth Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the unitholders for claims against Pengrowth Trust. Notwithstanding the foregoing, because of uncertainties in the law relating to trusts such as Pengrowth Trust, there is a risk that a unitholder could be held personally liable for obligations of Pengrowth Trust to the extent that claims are not satisfied by Pengrowth Trust.
TheIncome Trusts Liability Actpassed third reading on May 11, 2004 in the Alberta Legislative and now awaits royal ascent. The Act will apply to Alberta income trusts which include Pengrowth Trust by virtue of being a trust governed by the laws of the Province of Alberta and being a reporting issuer under theSecurities Act(Alberta). From and after coming into force, notwithstanding any express or implied indemnity of a trustee by a beneficiary of an Alberta income trust, the beneficiary will not, as a beneficiary, be liable for any act, default, obligation or liability of the trustee of the Alberta income trust.
Special Voting Unit
The authorized trust units include the special voting trust unit which entitles the holder thereof to a number of votes equal to the number of outstanding exchangeable shares of Pengrowth Corporation at any meeting of the unitholders. The special voting trust unit is not entitled to receive distributions from Pengrowth Trust. The special voting trust unit is intended to provide voting rights to the holders of exchangeable shares of Pengrowth Corporation equivalent to the voting rights attached to trust units. As of the date hereof, the special voting trust unit has not been issued.
2004 Annual and Special Meeting
At the annual and special meeting of unitholders on April 22, 2004, several amendments to the trust indenture were approved by the unitholders. See “General Development of Pengrowth Energy Trust — Recent Acquisitions, Financings and Developments — 2004 Annual and Special Meetings.”
THE ROYALTY INDENTURE
Royalty Units
Royalty units are issued under the terms of the royalty indenture dated June 17, 2003 (amending and restating royalty indenture dated April 23, 2002) between Pengrowth Corporation and Computershare, as trustee. A maximum of 500,000,000 royalty units can be created and issued pursuant to the royalty indenture. The royalty units represent fractional undivided interests in the royalty, consisting of a 99% share of “royalty income”.
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The royalty indenture, among other things, provides for the grant of the royalty, the issue of royalty units, the imposition on and acceptance by Pengrowth Corporation of certain obligations and business restrictions, the calling of meetings of unitholders, the conduct of business thereat, notice provisions, the appointment and removal of the trustee, and the establishment and use of the “reserve” as discussed below.
The royalty indenture may be amended or varied only by extraordinary resolution of the unitholders and the holders of royalty units, or by Pengrowth Corporation and Computershare, as trustee, for certain specifically defined purposes so long as, in the opinion of Computershare, the unitholders and the holders of royalty units are not prejudiced as a result.
The holders of royalty units other than the trustee are currently entitled to vote at shareholder meetings of Pengrowth Corporation on the basis of one vote for each royalty unit held.
At the special meeting of royalty unitholders held on April 22, 2004, amendments to the royalty indenture were approved by the unitholders to facilitate the issuance of exchangeable shares by Pengrowth Corporation. See “General Development of Pengrowth Energy Trust — Recent Acquisitions, Financing and Developments — 2004 Annual and Special Meetings.
The Royalty
The royalty consists of a 99% share of “royalty income”. Under the terms of the Royalty Indenture, Pengrowth Corporation is entitled to retain a 1 percent share of “royalty income” and all miscellaneous income (the “Residual Interest”) to the extent this amount exceeds the aggregate of debt service charges, general and administrative expenses, and management fees. In 2003 and 2002, this Residual Interest, as computed, did not result in any income being retained by Pengrowth Corporation. The royalty indenture provides that “royalty income” means the aggregate of any special distributions and gross revenue less, without duplication, the aggregate of the following amounts:
| (a) | operating costs; |
| (b) | general and administrative costs; |
| (c) | management fees and debt service charges; |
| (d) | taxes or other charges payable by Pengrowth Corporation; and |
| (e) | any amounts paid into the “reserve”. |
Gross revenues essentially consist of cash proceeds from the sale of petroleum substances produced from the properties of Pengrowth Corporation and all other money and things of value received by or incurring to Pengrowth Corporation by virtue of its legal and beneficial ownership of the properties, but not including processing or transportation revenues or proceeds from the sale of properties. Special distributions essentially consist of proceeds from the sale of properties that Pengrowth Corporation is unable to reinvest in suitable replacement properties.
The “reserve” is established by Pengrowth Corporation with miscellaneous revenues (such as processing and transportation revenues) and allowable portions of gross revenue, and must be used to fund the payment of operating costs, future abandonments, environmental and reclamation costs, general and administrative costs, management fees and debt service charges. Any amounts remaining in the reserve when there are no longer any properties that are subject to the royalty, and all of the above obligations have been satisfied, are to be paid to Pengrowth Trust and to the holders of common shares and exchangeable shares of Pengrowth Corporation in proportion to their respective interests.
Pengrowth Corporation is required to pay to the holders of royalty units, on each cash distribution date, 99% of “royalty income” received by Pengrowth Corporation from the properties for the period ending on the last day of the second month immediately preceding that cash distribution date less the percentage of distributable cash (currently 10%) that is retained by Pengrowth Corporation to fund capital obligations. See “Distributions”. The holders of royalty units, including Pengrowth Trust, will reimburse Pengrowth Corporation for 99% of the non-deductible Crown royalties and other non-deductible Crown charges payable by Pengrowth Corporation in respect of production from, or ownership of, the properties. Pengrowth Corporation will at all times be entitled to set off its right to be so reimbursed against its obligation to pay the royalty.
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To date, Pengrowth Corporation has not incurred income taxes but is subject to the federal large corporations tax and the Saskatchewan resource surcharge. Any taxes payable by Pengrowth Corporation will reduce royalty income, and thus the distributions received by unitholders and holders of royalty units.
The Trustee
Computershare is the trustee for holders of royalty units under the royalty indenture and will remain the trustee thereunder unless it resigns or is removed by unitholders. Computershare or its successor may resign on 60 days prior notice to the unitholders, and may be removed by extraordinary resolution of the unitholders. Computershare’s successor must be approved in the same manner.
Computershare, in accordance with its power to delegate under the trust indenture, has appointed Pengrowth Corporation as the administrator of Pengrowth Trust to assume those functions of the trustee which are largely discretionary pursuant to the royalty indenture, subject to the powers and duties of Pengrowth Management pursuant to the management agreement.
DISTRIBUTIONS
Pengrowth uses the term “distributable cash” to refer to the amount of cash that has been or is to be available for distribution to the unitholders. “distributable cash” is not a measure recognized by generally accepted accounting principles in Canada and does not have a standardized meaning prescribed by GAAP, but is an amount calculated in accordance with the terms of the royalty indenture. Therefore, distributable cash of Pengrowth may not be comparable to similar measures presented by other issuers, and investors are cautioned that distributable cash should not be construed as an alternative to net income, cash provided by operating activities or other measures of financial performance calculated in accordance with GAAP.
Distributable cash is typically paid in the form of distributions in the second month following the month in which they are earned. From time to time, the Board of Directors may determine, on behalf of Pengrowth Trust, to cause Pengrowth Trust to withhold a portion of the distributable cash in periods of high commodity prices in order to reduce the variability of distributions payable to unitholders resulting from commodity price fluctuations.
At the special meeting of the holders of royalty units held on April 23, 2002, the holders of royalty units amended the royalty indenture to permit the Board of Directors to establish a holdback, within Pengrowth Corporation, of up to 20% of its gross revenue if the Board of Directors determines that it would be advisable to do so in accordance with prudent business practices to provide for the payment of future capital expenditures or for the payment of royalty income in any future period. Subsequent to this action, the Board of Directors authorized the establishment of a holdback to fund future capital obligations and future payments of royalty income to Pengrowth Trust comprised of funds retained within Pengrowth Corporation in an amount equivalent to approximately 10% of the distributable cash of Pengrowth Trust calculated as if the reserve had not been established.
The following distributions per trust unit has been reported in respect of the quarters indicated since January 1, 2001:
| Quarter | 2003 | 2002 | 2001 | |||||||||
| First | $ | 0.75 | $ | 0.41 | $ | 1.14 | ||||||
| Second | 0.67 | 0.54 | 0.83 | |||||||||
| Third | 0.63 | 0.52 | 0.63 | |||||||||
| Fourth | 0.63 | 0.60 | 0.41 | |||||||||
| Total Annual | $ | 2.68 | $ | 2.07 | $ | 3.01 | ||||||
| Cumulative, since inception | $ | 26.08 | $ | 23.40 | $ | 21.33 | ||||||
INDUSTRY CONDITIONS
Government Regulation
The oil and natural gas industry is subject to extensive controls and regulation imposed by various levels of government. Although we do not expect that these controls and regulation will affect the operations of Pengrowth in a
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manner materially different than they would affect other oil and gas companies of similar size, the controls and regulations should be considered carefully by investors in the oil and gas industry. All current legislation is a matter of public record and Pengrowth is unable to predict what additional legislation or amendments may be enacted.
Pricing and Marketing — Oil
In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends, in part, on oil type and quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance, other contractual terms and the world price of oil. Oil exports may be made pursuant to export contracts with terms not exceeding one year, in the case of light crude, and not exceeding two years, in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board. Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the National Energy Board and the issue of such a licence requires the approval of the Governor in Council.
Pricing and Marketing — Natural Gas
In Canada, the price of natural gas sold in intraprovincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to market, access to downstream transportation, length of contract term, weather conditions, the supply/demand balance and other contractual terms. Natural gas exported from Canada is subject to regulation by the National Energy Board and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the National Energy Board and the government of Canada. Natural gas exports for a term of less than two years or for a term of 2 to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an order of the National Energy Board. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity, requires an exporter to obtain an export licence from the National Energy Board and the issue of such a licence requires the approval of the Governor in Council.
The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere, based on such factors as reserve availability, transportation arrangements and market considerations.
The North American Free Trade Agreement
On January 1, 1994, the North American Free Trade Agreement among the governments of Canada, the U.S. and Mexico became effective. The North American Free Trade Agreement carries forward most of the material energy terms contained in the Canada-United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements and, except as permitted in enforcement of countervailing and antidumping orders and undertakings, minimum or maximum import price requirements.
The North American Free Trade Agreement contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The North American Free Trade Agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.
Provincial Royalties and Incentives
The Federal and provincial governments in Canada have legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the freehold mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are
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generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location and field discovery date.
The Government of Alberta’s royalty structure includes incentives for exploring and developing oil and natural gas reserves. The incentives include a modification of the royalty formula structure through the implementation of a third tier royalty. For oil produced from wells drilled after October 13, 1992, oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The oil royalty reserved to the Crown on older oil wells has a base rate of 10% and a rate cap of 35%. The royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new gas, and between 15% and 35%, in the case of old gas, depending upon a prescribed or corporate average reference price.
In Alberta, certain producers of oil or natural gas are also entitled to a credit against the royalties payable to the Alberta Crown by virtue of the Alberta royalty tax credit program. The Alberta royalty tax credit program is based on a price-sensitive formula, and the Alberta royalty tax credit program rate varies between 75%, at prices for oil below $100 per cubic meter, and 25%, at prices above $210 per cubic meter. The Alberta royalty tax credit program rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from companies claiming maximum entitlement to Alberta royalty tax credit program will generally not be eligible for Alberta royalty tax credit program. The Alberta royalty tax credit program rate is established quarterly based on the average “par price”, as determined by the Alberta Resource Development Department for the previous quarterly period.
In British Columbia, the amount payable as a royalty in respect of oil depends on the vintage of the oil (whether it was produced from a pool discovered before or after October 31, 1975), the quantity of oil produced in a month and the value of the oil. Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production. The royalty payable on natural gas is determined by a sliding scale based on a reference price which is the greater of the amount obtained by the producer and a prescribed minimum price. Natural gas produced in association with oil has a minimum royalty of 8% while the royalty in respect of other natural gas may not be less than 15%.
On May 30, 2003, the Minister of Energy and Mines for British Columbia announced an Oil and Gas Development Strategy for the Heartlands. The strategy, which was updated in November 2003, is a comprehensive program to address road infrastructure, targeted royalties, and regulatory reduction and service-sector opportunities. Some of the financial incentives include: i) royalty credits of up to $30 million annually towards road infrastructure in support of resource development (Industry must make an equal contribution); ii) royalty credits for deep gas exploration, re-entry and horizontal drilling; and iii) royalty credits for unconventional and new basins.
The new fiscal regime for the Saskatchewan oil and gas industry effective October 1, 2002, provides an incentive to encourage exploration and development through a revised royalty/tax structure for oil and natural gas wells with a finished drilling date on or after October 1, 2002 or incremental oil production due to a new or expanded waterflood project with a commencement date on or after October 1, 2002. This “fourth tier” Crown royalty rate, applicable to both oil and natural gas, is price sensitive and ranges from a minimum 5% at a base price to a maximum of 30% at a price above the base price. A fourth tier freehold tax structure, calculated by subtracting a production tax factor of 12.5 percentage points from the corresponding Crown royalty rates, has also been created which is applicable to conventional oil, incremental oil from new or expanded waterfloods and natural gas. The fourth tier royalty/tax structure is also applicable in respect of associated natural gas that is gathered for use or sale which is produced either from oil wells with a finished drilling date on or after October 1, 2002 and oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of more than 3,500 m3 of natural gas per 1 m3 of oil. In addition, volume-based royalty/tax reduction incentives have been changed such that a maximum royalty of 2.5% now applies to various volumes of both oil and natural gas, depending on the depth and nature of the well (up to 16,000 m3 of oil in the case of deep exploratory wells and 25,000 m3 of natural gas produced from exploratory wells). The royalty/tax category with respect to re-entry and short sectional horizontal oil wells has been eliminated such that all horizontal oil wells with a finished drilling date on or after October 1, 2002 will receive fourth tier royalty/tax rates and incentive volumes. Further changes include the reduction of the corporation capital tax surcharge rate from 3.6% to 2.0% and the expansion of the “deep oil well” definition to include oil wells producing from a zone deeper than 1,700 meters provided that the zone is within a geological system deposited during the Mississippian Period or earlier or from a zone that was deposited before the Bakken zone regardless of depth.
The Government of Nova Scotia has established a generic royalty regime in respect of oil and gas produced from offshore Nova Scotia. Such regime contemplates a multi-tier royalty in which the royalty rate fluctuates when certain
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threshold levels of rates of return on capital have been reached. Notwithstanding the generic royalty regime, royalties in respect of offshore Nova Scotia oil and gas production may be determined contractually between the participant and the government of Nova Scotia.
Oil and natural gas royalty holidays and reductions for specific wells reduce the amount of Crown royalties paid by Pengrowth to the provincial governments. The Alberta royalty tax credit program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties. These incentives result in increased net income and funds from the operations of Pengrowth.
Environmental Regulation
The oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures. A breach of such legislation may result in the imposition of material fines and penalties, the revocation of necessary licenses and authorizations and civil liability for pollution damage.
In 1994, the United Nations’ Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which will require, upon ratification, nations to reduce their emissions of carbon dioxide and other greenhouse gases. As a consequence of the Kyoto Protocol, reductions in greenhouse gases from Pengrowth’s operations may be required which could result in increased capital expenditures and reductions in production of oil and gas. Pengrowth may however earn carbon credits offsetting liabilities which may be imposed under Kyoto due to Pengrowth’s participation in the carbon dioxide miscible recovery scheme at Weyburn and other potential tertiary recovery projects in the future.
Pengrowth is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment. Pengrowth Corporation will be taking such steps as required to ensure compliance with theAlberta Environmental Protection and Enhancement Act, theEnvironmental Assessment Act (British Columbia) and similar legislation or requirements in other jurisdictions in which it operates. Pengrowth believes that it is in material compliance with applicable environmental laws and regulations. Pengrowth also believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.
SELECTED FINANCIAL INFORMATION
Summary of Annual Financial Information
(Stated in thousands of dollars except per unit amounts)
Year ended December 31
(Audited)
| 2003 | 2002 | 2001 | ||||||||||
| Oil and Gas Revenue | $ | 682,795 | $ | 482,301 | $ | 469,929 | ||||||
| Net Income (Loss) | 189,297 | 56,955 | 88,185 | |||||||||
| Per trust unit — basic | 1.63 | 0.63 | 1.24 | |||||||||
| Total Assets | 1,673,718 | 1,552,651 | 1,270,208 | |||||||||
| Long Term Debt | 259,300 | 316,501 | 345,456 | |||||||||
| Distributable cash | 313,415 | 194,458 | 215,787 | |||||||||
| Per trust unit | 2.68 | 2.07 | 3.01 | |||||||||
Summary of Quarterly Financial Information
(Stated in thousands of dollars except per trust unit amounts)
Three months ended
(Unaudited)
| 2003 | March 31 | June 30 | September 30 | December 31 | ||||||||||||
| Oil and gas revenue | $ | 202,801 | $ | 167,222 | $ | 160,695 | $ | 152,077 | ||||||||
| Distributable cash | 97,221 | 71,774 | 72,951 | 71,469 | ||||||||||||
| Per trust unit | 0.75 | 0.67 | 0.63 | 0.63 | ||||||||||||
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| 2002 | March 31 | June 30 | September 30 | December 31 | ||||||||||||
| Oil and gas revenue | $ | 91,634 | $ | 111,544 | $ | 111,205 | $ | 167,918 | ||||||||
| Distributable cash | 33,118 | 48,141 | 46,139 | 67,060 | ||||||||||||
| Per trust unit | 0.41 | 0.54 | 0.52 | 0.60 | ||||||||||||
Notes:
| (1) | The per trust unit amount for net income is based on weighted average trust units outstanding calculated on a quarterly basis. The per trust unit amounts for distributable cash reflect actual distributions paid or declared. |
| (2) | Certain comparative figures have been restated to conform to the presentation adopted in the current year. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
OPERATING RESULTS AND FINANCIAL CONDITION
Management’s Discussion and Analysis relating to Pengrowth Trust’s financial statements for the fiscal years ended December 31, 2003 and 2002, which are contained on pages 42 to 65 of Pengrowth Trust’s 2003 Annual Report, are incorporated herein by reference and form an integral part of this Annual Information Form.
MARKET FOR SECURITIES
Our outstanding trust units are listed and posted for trading on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange (“NYSE”). The trading symbol for the trust units on the TSX is “PGF.UN” and on the NYSE is “PGH”. At the annual and special meeting of unitholders on April 22, 2004, several amendments to the trust indenture were approved by the unitholders to permit the reclassification of existing trust units into Class B trust units which may only be held by Canadian residents and will only trade on the TSX and Class A trust units which are unrestricted and will trade on the TSX and the NYSE. See “General Development of Pengrowth Energy Trust — Recent Acquisitions, Financings and Developments — 2004 Annual and Special Meetings.
DIRECTORS AND OFFICERS
Pengrowth Trust does not have any directors or officers. The following is a summary of information relating to the directors and officers respectively of Pengrowth Management, Pengrowth Management of Pengrowth Corporation and Pengrowth Trust, and of Pengrowth Corporation, the administrator of Pengrowth Trust.
Directors and Officers of Pengrowth Management
The name, municipality of residence, position held and principal occupation of each director and officer of Pengrowth Management are set out below:
| Name and | ||||
| Municipality of Residence | Position with Pengrowth Management | Principal Occupation | ||
| James S. Kinnear | President and Director | President, | ||
| Calgary, Alberta | (since 1982) | Pengrowth Management Limited | ||
| Gregory S. Fletcher | Director | President, | ||
| Calgary, Alberta | (since 1988) | Sierra Energy Inc. | ||
| Gordon M. Anderson Calgary, Alberta | Vice President, Financial Services (since 2001) Vice President, Treasurer (1998-2001) | Vice President, Financial Services Pengrowth Management Limited | ||
| Treasurer (1995-1998) | ||||
| Charles V. Selby | Corporate Secretary | Lawyer, Selby Professional Corporation | ||
| Calgary, Alberta | (since 1993) | Principal, Ikon Strategies Inc. |
Each of the foregoing directors and officers has had the same principal occupation for the previous five years except for: Mr. Fletcher who was President, Canadian Conquest Exploration Inc. (1998-1999); and Mr. Anderson who was Vice President, Treasurer (1998-2001).
Principal Holders of Shares of Pengrowth Management
James S. Kinnear, President and a director of Pengrowth Management and Chairman, President, Chief Executive Officer and a director of Pengrowth Corporation, owns, directly or indirectly, all of the issued and outstanding voting securities of Pengrowth Management.
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Directors and Officers of Pengrowth Corporation
The name, municipality of residence, position held and principal occupation of each director and officer of Pengrowth Corporation are set out below:
| Trust Units of | ||||||||
| Name and | Controlled or | |||||||
| Municipality of | Beneficially | |||||||
| Residence | Position with Pengrowth Corporation | Principal Occupation | Owned(1)(2) | |||||
| James S. Kinnear Calgary, Alberta | President, Chairman, Director and Chief Executive Officer | President, Pengrowth Management Limited | 3,197,933 | (6) | ||||
| (since 1988) | ||||||||
Stanley H. Wong(4) Calgary, Alberta | Director (since 1988) | President, Carbine Resources Ltd. a private oil and gas producing and | 44,076 | (7) | ||||
| engineering consulting company | ||||||||
John B. Zaozirny(5) Calgary, Alberta | Director (since 1988) | Counsel, McCarthy Tétrault, Barristers and | 31,328 | |||||
| Solicitors | ||||||||
Thomas A. Cumming(3)(5) | Director | |||||||
| Calgary, Alberta | (since 2000) | Business Consultant | 6,678 | |||||
Michael Grandin(3)(5)(8) | Director | Chairman and Chief Executive Officer, | 3,100 | |||||
| Calgary, Alberta | (since 2002) | Fording Canadian Coal Trust and Dean, Haskayne School of Business, University of Calgary | ||||||
Michael S. Parrett(3) | Director | |||||||
| Aurora, Ontario | (since 2004) | Business Consultant | nil | |||||
William R. Stedman(4) | Director | Chairman and Chief Executive | nil | |||||
| Calgary, Alberta | (since 2004) | Officer, ENTx Capital Corporation | ||||||
| Robert B. Hodgins | Chief Financial Officer | Chief Financial Officer | 5,008 | |||||
| Calgary, Alberta | (since 2002) | Pengrowth Corporation | ||||||
| Gordon M. Anderson Calgary, Alberta | Vice President (since 2001) Vice President, Treasurer (1997-2001), Treasurer (1995-1997) | Vice President, Financial Services, Pengrowth Management Limited | 33,594 | |||||
| Chief Financial Officer (1991-1998) | ||||||||
| Henry D. McKinnon | Vice President, Operations | Vice President, Operations | 7,258 | |||||
| Calgary, Alberta | (since 2000) | Pengrowth Corporation | ||||||
| Lynn Kis | Vice President, Engineering | Vice President, Engineering | 23,379 | |||||
| Calgary, Alberta | (since 2001) | Pengrowth Corporation | ||||||
| Charles V. Selby Calgary, Alberta | Corporate Secretary (since 1993) | Lawyer, Selby Professional Corporation Principal, Ikon Strategies Inc. | 121,021 | |||||
| Chris Webster | Treasurer | Treasurer | 6,569 | |||||
| Calgary, Alberta | (since 2001) | Pengrowth Corporation | ||||||
| Lianne Bigham | Controller | Controller | 96,875 | |||||
| Calgary, Alberta | (since 1996) | Pengrowth Corporation | ||||||
Notes:
| (1) | Does not include trust units issuable upon the exercise of outstanding trust unit options or trust unit rights. |
| (2) | As at December 31, 2003. |
| (3) | Member of Audit Committee. |
| (4) | Member of Reserves Committee. |
| (5) | Member of Corporate Governance/Compensation Committee. |
| (6) | Comprised of 1,199,104 trust units held personally and 1,998,829 trust units held by Kinnear Financial Consulting Limited. In addition, Mr. Kinnear exercises control over 13,152 royalty units which are held by Pengrowth Management Limited. |
| (7) | In addition, Mr. Wong exercises control over 3,288 royalty units held by Carbine Resources Ltd. |
| (8) | Mr. Grandin was a director of Pegasus Gold Inc. in 1988 when that company filed voluntarily to reorganize under Chapter 11 of the Bankruptcy Code (United States). A liquidation plan for that company received court confirmation later that year. |
Each of the foregoing directors and officers has had the same principal occupation for the previous five years except for Mr. Cumming who was President of the Alberta Stock Exchange from 1988 to 1999; Michael Grandin who was Executive Vice-President and Chief Financial Officer, Canadian Pacific Limited in 2000 and President, PanCanadian Energy Corporation in 2001 and has served as Chairman and Chief Executive Officer of Fording Canadian Coal Trust since 2003; Michael S. Parrett who was Vice-President and Chief Financial Officer of Rio Algom Limited (“Rio”) from 1991 to
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2000, Vice-President, Strategic Development and Joint Ventures of Rio from 1999 to 2000, President of Rio from 2000 to 2001; William R. Stedman who was President and CEO of Pembina Pipeline Corporation from 1997 to 1999; Robert B. Hodgins who was Vice President and Treasurer of Canadian Pacific Limited from 1998 to 2001 and Chief Financial Officer of TransCanada Pipelines Limited from 1993 to 1998; Lynn Kis who was General Manager, Engineering from 1998 to 2001; and Chris Webster who was Manager, Operations Accounting from 2000 to 2001 and Team Leader, Marketing Accounting and Treasury, Union Pacific Resources Inc. from 1996 to 2000.
RISK FACTORS
If any of the following risks occur, our production, revenues and financial condition could be materially harmed, with a resulting decrease in distributions on, and the market price of, our trust units. As a result, the trading price of our trust units could decline, and you could lose all or part of your investment.
Our distributions are sensitive to the volatility of crude oil and natural gas prices.
The monthly distributions we pay to our unitholders depend, in part, on the prices we receive for our oil and natural gas production. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond our control. These factors include, among others:
| • | political conditions in the Middle East; |
| • | worldwide economic conditions; |
| • | weather conditions; |
| • | the supply and price of foreign oil and natural gas; |
| • | the level of consumer demand; |
| • | the price and availability of alternative fuels; |
| • | the proximity to, and capacity of, transportation facilities; |
| • | the effect of worldwide energy conservation measures; and |
| • | government regulation. |
Declines in oil or natural gas prices could have an adverse effect on our operations, financial condition and proved reserves and ultimately on our ability to pay distributions to our unitholders.
Our distributions are affected by production and development costs and capital expenditures.
Production and development costs incurred with respect to properties, including power costs and the costs of injection fluids associated with tertiary recovery operations, reduce the royalty income that Pengrowth Trust receives and, consequently, the amounts we can distribute to our unitholders.
The timing and amount of capital expenditures will directly affect the amount of income available for distribution to our unitholders. Distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made. To the extent that external sources of capital, including the issuance of additional trust units, become limited or unavailable, Pengrowth Corporation’s ability to make the necessary capital investments to maintain or expand oil and gas reserves and to invest in assets, as the case may be, will be impaired. To the extent that Pengrowth Corporation is required to use cash flow to finance capital expenditures or property acquisitions, the cash we receive from Pengrowth Corporation on the royalty units will be reduced, resulting in reductions to the amount of cash we are able to distribute to our unitholders.
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Our actual results will vary from our reserve estimates, and those variations could be material.
The value of the trust units will depend upon, among other things, Pengrowth Corporation’s reserves. In making strategic decisions, we generally rely upon reports prepared by our independent reserve engineers. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Changes in the prices of, and markets for, oil and natural gas from those anticipated at the time of making such assessments will affect the return on, and value of, our trust units. The reserve and cash flow information contained in this Annual Information Form or contained in the documents incorporated by reference represent estimates only. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include:
| • | historical production from the area compared with production rates from similar producing areas; |
| • | the assumed effect of government regulation; |
| • | assumptions about future commodity prices, exchange rates, production and development costs, capital expenditures, abandonment costs, environmental liabilities, and applicable royalty regimes; |
| • | initial production rates; |
| • | production decline rates; |
| • | ultimate recovery of reserves; |
| • | marketability of production; and |
| • | other government levies that may be imposed over the producing life of reserves. |
If these factors and assumptions prove to be inaccurate, our actual results may vary materially from our reserve estimates. Many of these factors are subject to change and are beyond our control. In particular, changes in the prices of, and markets for, oil and natural gas from those anticipated at the time of making such assessments will affect the return on, and value of, our trust units. In addition, all such assessments involve a measure of geological and engineering uncertainty that could result in lower production and reserves than anticipated. A significant portion of our reserves are classified as “undeveloped” and are subject to greater uncertainty than reserves classified as “developed”.
In accordance with normal industry practices, we engage independent petroleum engineers to conduct a detailed engineering evaluation of our oil and gas properties for the purpose of estimating our reserves as part of our year-end reporting process. As a result of that evaluation, we may increase or decrease the estimates of our reserves. We do not consider an increase or decrease in the estimates of our reserves in the range of one to five percent to be material or inconsistent with normal industry practice. Any significant reduction to the estimates of our reserves resulting from any such evaluation could have a material adverse effect on the value of our trust units.
Our reserves will be depleted over time and our level of distributable cash and the value of our trust units could be reduced if reserves are not replaced.
Our future oil and natural gas reserves and production, and therefore the cash flows of Pengrowth Trust, will depend upon our success in acquiring additional reserves. If we fail to add reserves by acquiring or developing them, our reserves and production will decline over time as they are produced. When reserves from our properties can no longer be economically produced and marketed, our trust units will have no value unless additional reserves have been acquired or developed. If we are not able to raise capital on favourable terms, we may not be able to add to or maintain our reserves. If we use our cash flow to acquire or develop reserves, we will reduce our distributable cash. There is strong competition in all aspects of the oil and gas industry including reserve acquisitions. We will actively compete for reserve acquisitions and skilled industry personnel with a substantial number of other oil and gas companies and energy trusts. However, many of our competitors have greater resources than we do and we cannot assure you that we will be successful in acquiring additional reserves on terms that meet our objectives.
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Our operation of oil and natural gas wells could subject us to environmental claims and liability.
The oil and natural gas industry is subject to extensive environmental regulation, which imposes restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations. In addition, Canadian legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of this or other legislation may result in fines or the issuance of a clean-up order. Ongoing environmental obligations will be funded out of our cash flow and could therefore reduce distributable cash payable to our unitholders.
We may be unable to successfully compete with other companies in our industry.
There is strong competition in all aspects of the oil and gas industry. Pengrowth will actively compete for capital, skilled personnel, undeveloped lands, reserve acquisitions, access to drilling rigs, service rigs and other equipment, access to processing facilities and pipeline and refining capacity and in all other aspects of its operations with a substantial number of other organizations, many of which may have greater technical and financial resources than Pengrowth. Some of those organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market oil and other products on a world-wide basis and, as such, have greater and more diverse resources on which to draw.
Incorrect assessments of value at the time of acquisitions could adversely affect the value of our trust units and our distributions.
Acquisitions of oil and gas properties or companies will be based in large part on engineering and economic assessments made by independent engineers. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated.
Our level of debt could have a material adverse effect on our ability to pay distributions to our unitholders.
Pengrowth Corporation has issued US$200 million in term debt due in two tranches, the first tranche of US$150 million is due in April 2010 and the second tranche of US$50 million is due in April 2013. Pengrowth also has a $200 million revolving credit facility syndicated among eight financial institutions in place until June 20, 2004. The $200 million facility has a 364 day revolving period and should it not be renewed on June 20, 2004, it will be repayable over a two year period. Pengrowth also has a $35 million demand operating line of credit. We draw upon these credit facilities from time to time to make acquisitions of oil and natural gas properties and to fund capital investments in our properties. We pay interest at fluctuating rates with respect to a portion of our outstanding debt under our existing credit facilities. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount Pengrowth is required to apply to service its debt. Certain covenants in the agreements with our lenders may also limit the amount of the royalty paid by Pengrowth Corporation to Pengrowth Trust and the distributions paid by us to our unitholders. On April 8, 2004, Pengrowth Corporation entered into an agreement with a subsidiary of Murphy Oil Corporation to acquire oil and natural gas assets through the purchase of shares in a numbered company for $550 million which will be funded through cash on hand and through a committed interim debt facility provided by Pengrowth Corporation’s lead banker. Pengrowth Corporation will seek to replace the interim credit facility with other sources of financing. We cannot assure you that the amount of our credit facility will be adequate for our future financial obligations or that we will be able to obtain additional funds. If we become unable to pay our debt service charges or otherwise cause an event of default to occur, our lenders may foreclose on or sell the properties. The net proceeds of any such sale will be allocated firstly, to the repayment of our lenders and other creditors and only the remainder, if any, would be payable to Pengrowth Trust by Pengrowth Corporation in respect of the royalty.
Loss of our key management and other personnel could impact our business.
Our unitholders are entirely dependent on the management of Pengrowth Management and Pengrowth Corporation with respect to the acquisition of oil and gas properties and assets, the development and acquisition of additional reserves, the management and administration of all matters relating to properties and the administration of Pengrowth Trust. The loss of the services of key individuals who currently comprise the management team of Pengrowth Management and Pengrowth Corporation could have a detrimental effect on Pengrowth Trust. In addition, increased activity within the oil and gas sector can increase the cost of goods and services and make it more difficult to have and retain qualified professional staff.
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Trust distributions are affected by marketability of production.
The marketability of our production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. United States federal and state and Canadian federal and provincial regulation of oil and gas production and transportation, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors dramatically change, the financial impact on us could be substantial. The availability of markets is beyond our control.
The operation of a significant portion of our properties is largely dependent on the ability of third party operators, and harm to their business could cause delays and additional expenses in our receiving revenues.
The continuing production from a property, and to some extent the marketing of production, is dependent upon the ability of the operators of our properties. Currently 42% of our properties are operated by third parties, based on daily production. If, in situations where we are not the operator, the operator fails to perform these functions properly or becomes insolvent, then revenues may be reduced. Revenues from production generally flow through the operator and, where we are not the operator, there is a risk of delay and additional expense in receiving such revenues.
The operation of the wells located on properties not operated by us are generally governed by operating agreements which typically require the operator to conduct operations in a good and workmanlike manner. Operating agreements generally provide, however, that the operator will have no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except such as may result from gross negligence or wilful misconduct. In addition, third-party operators are generally not fiduciaries with respect to Pengrowth Corporation, Pengrowth Trust or the unitholders. Pengrowth Corporation, as owner of working interests in properties not operated by it, will generally have a cause of action for damages arising from a breach of the operator’s duty. Although not established by definitive legal precedent, it is unlikely that the Pengrowth Trust or our unitholders would be entitled to bring suit against third-party operators to enforce the terms of the operating agreements. Therefore, our unitholders will be dependent upon Pengrowth Corporation, as owner of the working interest, to enforce such rights.
Our distributions could be adversely affected by unforeseen title defects.
Although title reviews are conducted prior to any purchase of resource assets, such reviews cannot guarantee that an unforeseen defect in the chain of title will not arise to defeat our title to certain assets. Such defects could reduce the amounts distributable to our unitholders, and could result in a reduction of capital.
Fluctuations in foreign currency exchange rates could adversely affect our business.
World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/United States dollar exchange rate which fluctuates over time. A material increase in the value of the Canadian dollar may negatively impact our net production revenue and cash flow. To the extent that we have engaged, or in the future engage, in risk management activities related to commodity prices and foreign exchange rates, through entry into oil or natural gas price hedges and forward foreign exchange contracts or otherwise, we may be subject to unfavourable price changes and credit risks associated with the counterparties with which we contract.
A decline in the value of the Canadian dollar relative to the United States dollar provides a competitive advantage to United States companies in acquiring Canadian oil and gas properties and may make it more difficult for us to replace reserves through acquisitions.
Our insurance coverage could be inadequate.
We are exposed to a number of risks and maintain liability insurance, where available, in amounts consistent with industry standards. However, we may become liable for damages arising from events against which we cannot insure, or against which we may elect not to insure because of high premium costs or other reasons. The costs to repair such damage or pay such liabilities could reduce distributable income. Our operations are subject to all of the risks normally associated with drilling for, and the production and transportation of oil and natural gas. Such risks and hazards include encountering unexpected formations or pressures, blow-outs, craterings and fires, all of which could result in personal injury, loss of life, property damage and environmental damage. Although we have safety and environmental policies in place to protect operators and employees, as well as to meet regulatory requirements, and although we have liability insurance policies in
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place, we cannot fully insure against all such risks. Costs incurred to repair such damage or pay such liabilities will reduce payments made by Pengrowth Corporation to Pengrowth Trust.
Being a limited purpose trust makes Pengrowth Trust largely dependent upon the operations and assets of Pengrowth Corporation.
Pengrowth Trust is a limited purpose trust which is dependent upon the operations and assets of Pengrowth Corporation. Pengrowth Corporation’s income will be received from the production of crude oil and natural gas from its properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. Since the primary focus is to pursue growth opportunities through the development of existing reserves and the acquisition of new properties, Pengrowth Corporation’s involvement in the exploration for oil and natural gas is minimal. As a result, if the oil and natural gas reserves associated with Pengrowth Corporation’s resource properties are not supplemented through additional development or the acquisition of oil and natural gas properties, the ability of Pengrowth Corporation to continue to generate cash flow for distribution to unitholders may be adversely affected.
The SOEP properties may present challenges and risks that we have not faced in the past.
The SOEP properties are offshore and Pengrowth has had no other experience with offshore projects. Moreover, they are in an earlier stage of development than most of our previous acquisitions have been and have not been on production for an extended period of time. As a result, the SOEP properties may present challenges and risks that Pengrowth has not faced in the past. Furthermore, because of the early stage of development and relatively brief production history of these properties, events which could materially adversely affect our interests are more likely to occur. No assurance can be given that capital obligations will not be greater than forecast and that there will not be further negative revisions to reserves.
Management may have conflicts of interest.
Pengrowth Management provides advisory, management and administrative needs of Pengrowth Trust and Pengrowth Corporation in consideration for a management fee which is currently based in part on net production revenue of Pengrowth Corporation. This arrangement may create an incentive for Pengrowth Management to maximize the net production revenue of Pengrowth Corporation, rather than maximizing its distributable cash, which is the primary basis for calculating distributions available to unitholders.
Pengrowth Management may manage and administer such additional acquired properties, as well as enter into other types of energy related management and advisory activities and may not devote full time and attention to the business of Pengrowth Corporation and therefore act in contradiction to or competition with the interests of our unitholders.
General and administrative expenses which Pengrowth Management incurs in relation to the business of Pengrowth Corporation and Pengrowth Trust are required to be paid by Pengrowth Corporation. These expenses are not subject to a limit other than as may be provided under a periodic review by the Board of Directors and, as a result, there may not be an incentive for Pengrowth Management to minimize these expenses.
We may incur material costs to comply with, or as a result of, health, safety and environmental laws and regulations.
Compliance with environmental laws and regulations could materially increase our costs. We may incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as the Kyoto Protocol that is intended to reduce emissions of pollutants into the air.
Lower oil and gas prices increase the risk of write-downs of our oil and gas property investments.
Under Canadian accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” which is based, in part, upon estimated future net cash flows from reserves. If the net capitalized costs exceed this limit, we must charge the amount of the excess against earnings. As oil and gas prices decline, our net capitalized cost may approach and, in certain circumstances, exceed this cost ceiling, resulting in a charge against earnings. Under United States accounting rules, the cost ceiling is generally lower than under Canadian rules because the future net cash flows used in the United States ceiling test are discounted to a present value. Accordingly, we would have more risk of a ceiling test write-
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down in a declining price environment if we reported under United States generally accepted accounting principles. While these write-downs would not affect cash flow, the charge to earnings could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in our current or future credit agreements or other debt instruments.
Changes in Canadian legislation could adversely affect the value of our trust units.
The value of the trust units is largely related to our income tax treatment. We cannot assure you that income tax laws and government incentive programs relating to the oil and natural gas industry generally, the status of royalty trusts having our structure, the Alberta royalty tax credit and the resource allowance will remain favourable and not change in a manner that adversely affects your investment.
If Pengrowth Trust ceases to qualify as a mutual fund trust it would adversely affect the value of our trust units.
It is intended that Pengrowth Trust will at all times qualify as a mutual fund trust for the purposes of the Tax Act. While Pengrowth Trust may have an alternative basis for qualifying as a mutual fund trust, Pengrowth Trust intends to take measures to ensure that it qualifies as a mutual fund trust on the basis that it is not reasonable, at any time, to consider that Pengrowth Trust was established or is maintained primarily for the benefit of non-residents of Canada.
Recent residency information received by Pengrowth regarding the beneficial ownership of trust units indicates that a majority of trust units are owned by non-residents of Canada. However, it is the view of Pengrowth Corporation that Pengrowth Trust is not being maintained primarily for the benefit of non-residents as it is continuing to undertake measures to monitor, control and ultimately reduce the level of non-resident ownership, including implementation of the reclassification of the outstanding Trust Units as Class A and B Trust Units, where the Class B Trust Units may not be owned by non-residents of Canada and will constitute greater than 50% of the outstanding trust units. See “General Development of Pengrowth Energy Trust — Recent Acquisitions, Financings and Developments — 2004 Annual and Special Meetings — Reclassification of Trust Unit Capital”.
Notwithstanding the steps taken or to be taken by Pengrowth, no assurance can be given that the status of Pengrowth Trust as a mutual fund trust will not be challenged by a relevant taxation authority. If Pengrowth Trust’s status as a mutual fund trust is determined to have been lost, certain negative tax consequences will have resulted for Pengrowth Trust and its unitholders. These negative tax consequences include the following:
| • | The trust units would cease to be a qualified investment for trusts governed by RRSPs, RRIFs, RESPs and DPSPs, as defined in theIncome Tax Act(Canada) (the “Tax Act”). Where, at the end of a month, a RRSP, RRIF, RESP or DPSP holds trust units that ceased to be a qualified investment, the RRSP, RRIF, RESP or DPSP, as the case may be, must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1% of the fair market value of the trust units at the time such trust units were acquired by the RRSP, RRIF, RESP or DPSP. In addition, trusts governed by a RRSP or a RRIF which hold trust units that are not qualified investments will be subject to tax on the income attributable to the trust units while they are non-qualified investments, including the full capital gains, if any, realized on the disposition of such trust units. Where a trust governed by a RRSP or a RRIF acquires trust units that are not qualified investments, the value of the investment will be included in the income of the annuitant for the year of the acquisition. Trusts governed by RESPs which hold trust units that are not qualified investments can have their registration revoked by the Canada Revenue Agency. |
| • | Pengrowth Trust would be required to pay a tax under Part XII.2 of the Tax Act. The payment of Part XII.2 tax by Pengrowth Trust may have adverse income tax consequences for certain unitholders, including non-resident persons and residents of Canada who are exempt from Part I tax. |
| • | The trust units would be foreign property for RRSPs, RRIFs DPSPs and other persons subject to tax under Part XI of the Tax Act. |
| • | Pengrowth Trust would not be entitled to use the capital gains refund mechanism otherwise available for mutual fund trusts. |
| • | The trust units would constitute taxable Canadian property for the purposes of the Tax Act, potentially subjecting non-residents of Canada to tax pursuant to the Tax Act on the disposition (or deemed disposition) of such trust units. |
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The ability of investors resident in the United States to enforce civil remedies may be affected for a number of reasons.
Pengrowth Trust is an Alberta trust and Pengrowth Management and Pengrowth Corporation are both Alberta corporations. All of these entities have their principal places of business in Canada. All of the directors and officers of Pengrowth Management and Pengrowth Corporation are residents of Canada and all or a substantial portion of the assets of such persons and of Pengrowth Trust are located outside of the United States. Consequently, it may be difficult for United States investors to effect service of process within the United States upon Pengrowth Trust or such persons or to realize in the United States upon judgments of courts of the United States predicated upon civil remedies under theSecurities Act of 1933(United States), as amended. Investors should not assume that Canadian courts:
| (a) | will enforce judgments of United States courts obtained in actions against Pengrowth Trust or such persons predicated upon the civil liability provisions of the United States federal securities laws or the securities or “blue sky” laws of any state within the United States; or |
| (b) | will enforce, in original actions, liabilities against Pengrowth Trust or such persons predicated upon the United States federal securities laws or any such state securities or blue sky laws. |
Our trust units are not equivalent to shares.
Trust units should not be viewed by investors as shares in Pengrowth Corporation. Trust units are also dissimilar to conventional debt instruments in that there is no principal amount owing to our unitholders. Trust units represent a fractional interest in Pengrowth Trust. unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. Pengrowth Trust’s assets are royalty units and common shares of Pengrowth Corporation and certain facilities interests, and may also include certain other investments permitted under the trust indenture. The price per trust unit is a function of anticipated distributable cash, the oil and natural gas properties acquired by Pengrowth Corporation and the ability to effect long-term growth in the value of Pengrowth Corporation. The market price of the trust units will be sensitive to a variety of market conditions including, but not limited to, interest rates and the ability of Pengrowth Corporation to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of our trust units.
Trust units will have no value when reserves from the properties can no longer be economically produced or marketed and, as a result, cash distributions do not represent a “yield” in the traditional sense as they represent both return of capital and return on investment. unitholders will have to obtain the return of capital invested out of cash flow derived from their investments in the trust units during the period when reserves can be economically recovered. Accordingly, we give no assurances that the distributions you receive over the life of your investment will meet or exceed your initial capital investment.
You may experience substantial future dilution given that the success of Pengrowth Trust is dependent upon raising capital.
One of our objectives is to continually add to our reserves through acquisitions and through development. Our success is, in part, dependent on our ability to raise capital from time to time. Unitholders may also suffer dilution in connection with future issuance of trust units.
The limited liability of unitholders is uncertain.
The trust indenture provides that no unitholder will be subject to any personal liability in connection with Pengrowth Trust or its obligations and affairs, and the satisfaction of claims of any nature arising out of or in connection therewith is only to be made out of Pengrowth Trust’s assets. Additionally, the trust indenture states that no unitholder is liable to indemnify or reimburse Computershare for any liabilities incurred by Computershare with respect to any taxes payable by or liabilities incurred by Pengrowth Trust or Computershare, and all such liabilities will be enforceable only against, and will be satisfied only out of, Pengrowth Trust’s assets. It is intended that the operations of Pengrowth Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the unitholders for claims against Pengrowth Trust. Notwithstanding the foregoing, because of uncertainties in the law relating to trusts such as Pengrowth Trust, there is a risk that a unitholder could be held personally liable for obligations of Pengrowth Trust to the extent that claims are not satisfied by Pengrowth Trust.
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TheIncome Trusts Liability Actpassed third reading on May 11, 2004 in the Alberta Legislative and now awaits royal ascent. The Act will apply to Alberta income trusts which include Pengrowth Trust by virtue of being a trust governed by the laws of the Province of Alberta and being a reporting issuer under theSecurities Act(Alberta). From and after coming into force, notwithstanding any express or implied indemnity of a trustee by a beneficiary of an Alberta income trust, the beneficiary will not, as a beneficiary, be liable for any act, default, obligation or liability of the trustee of the Alberta income trust.
Canadian and United States practices differ in reporting reserves and production.
We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the United States Securities and Exchange Commission by companies in the United States.
We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the United States Securities and Exchange Commission and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves; however, we separately estimate our reserves using prices and costs held constant at the effective date of the reserve report in accordance with the Canadian reserve reporting requirements. These requirements are similar to the constant pricing reserve methodology utilized in the United States.
We include in this Annual Information Form estimates of proved and proved plus probable reserves. The United States Securities and Exchange Commission generally prohibits the inclusion of estimates of probable reserves in filings made with it. This prohibition does not apply to Pengrowth Trust because it is a Canadian foreign private issuer.
You may be required to pay taxes even if you do not receive any cash distributions.
You may be required to pay federal income taxes and, in some cases, state, provincial and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.
Unitholders who are United States persons face income tax risks.
The United States federal income tax risks related to owning and disposing of our trust units, include the following:
| • | Because the trust units will be publicly traded, Pengrowth Trust will not be treated as a corporation for U.S. federal income tax purposes only if 90% or more of its gross income consists of qualifying income. Although Pengrowth Trust expects to satisfy the 90% requirement at all times, if it fails to satisfy this requirement, it will be treated as a foreign corporation. If Pengrowth Trust were treated as a corporation, it could be a passive foreign investment company or “PFIC”. Treatment of Pengrowth Trust as a PFIC could result in a material reduction in the after-tax return to the unitholders, likely causing a substantial reduction in the value of the trust units. |
| • | A successful U.S. Internal Revenue Service (“IRS”) contest of the federal income tax positions we take or have taken may adversely affect the market for our trust units. For example, the IRS could challenge our position that the royalty from Pengrowth Corporation should be treated as a non-operating, non-working interest. We have not requested a ruling from the IRS with respect to this or any other matter affecting us other than relating to the timeliness of our election to be treated as a partnership. The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take or have taken. It may be necessary to resort to administrative or court proceedings to sustain our counsel’s conclusions or those positions. A court may not concur with our counsel’s conclusions or the positions we take or have taken. Any contest with the IRS may materially and adversely impact the U.S. federal income tax consequences to unitholders and, therefore, the market for our trust units and the price at which they |
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| trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne by us and indirectly by the unitholders. |
| • | Tax gain or loss on disposition of trust units could be different from expected. If you sell your trust units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in the trust units. Prior distributions in excess of the total net taxable income you were allocated, which decreased your tax basis in the trust units, will, in effect, become taxable income to you if the trust units are sold at a price greater than your tax basis in those trust units, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. Should the IRS successfully contest some positions we take, you could recognize more gain on the sale of trust units than would be the case under those positions, without the benefit of decreased income in prior years. Also, if you sell trust units, you may incur a tax liability in excess of the amount of cash you receive from the sale. |
| • | We have registered with the IRS as a “tax shelter.” This may increase the risk of an IRS audit of us or a unitholder. The tax laws require that some types of entities register as “tax shelters” in response to the perception that they claim tax benefits that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders’ tax returns and may lead to audits of unitholders’ tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return. |
| • | We will treat each owner of trust units as having the same tax benefits without regard to the specific trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of our trust units. Because we cannot match transferors and transferees of our trust units, we will adopt depletion, depreciation and amortization positions that do not conform with all aspects of final Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of trust units and could have a negative impact on the value of our trust units or result in audit adjustments to your tax returns. |
| • | Pengrowth Trust may not be an appropriate investment for certain types of entities. For example, there is a risk that some of Pengrowth Trust’s income could be unrelated business taxable income with respect to tax-exempt organizations. Furthermore, we anticipate that substantially all of Pengrowth Trust’s gross income will not be “qualifying income” for purposes of the rules relating to regulated investment companies. |
CONFLICTS OF INTEREST
There may be situations in which the interests of Pengrowth Management will conflict with those of our unitholders. Pengrowth Management may acquire oil and natural gas properties on behalf of persons other than the unitholders. Pengrowth Management may manage and administer such additional properties, as well as enter into other types of energy-related management and advisory activities. Accordingly, neither Pengrowth Management nor its management will carry on their full-time activities on behalf of unitholders and, when acting on behalf of others, may at times act in contradiction to or competition with the interests of unitholders. In the event that the interests of Pengrowth Management are in conflict with those of our unitholders, Pengrowth Management is obliged to make decisions acting in good faith, having regard to the best interests of unitholders and in a manner that would not contravene its fiduciary obligations to unitholders.
Although Pengrowth Management provides advisory and management services to Pengrowth Corporation and Pengrowth Trust, the Board of Directors supervises the management of the business and affairs of Pengrowth Corporation and Pengrowth Trust. The Board of Directors makes significant operational decisions and all decisions relating to:
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| (i) | the issuance of additional trust units; |
| (ii) | material acquisitions and dispositions of properties; | |||
| (iii) | material capital expenditures; | |||
| (iv) | borrowing; and | |||
| (v) | the payment of distributable cash. |
Properties may not be acquired from officers or directors of Pengrowth Management or persons not at arm’s length with such persons at prices which are greater than fair market value and properties may not be sold to officers or directors of Pengrowth Management or persons not at arm’s length with such persons at prices which are less than fair market value, in each case as established by an opinion of an independent financial advisor and approved by the independent members of the Board of Directors. There may be circumstances where certain transactions may also require the preparation of a formal valuation and the affirmative vote of unitholders in accordance with the requirements of Ontario Securities Commission Rule 61-501 — Insider Bids, Issuer Bids, Going Private Transactions and Related Party Transactions.
Circumstances may arise where members of the Board of Directors serve as directors or officers of corporations which are in competition to the interests of Pengrowth Corporation and Pengrowth Trust. No assurances can be given that opportunities identified by such board members will be provided to Pengrowth Corporation and Pengrowth Trust.
CODE OF ETHICS
Pengrowth has adopted a code of ethics, as that term is defined in Form 40-F under the U.S. Securities Exchange Act of 1934 (the “Code of Ethics”) that applies to Pengrowth’s management, including its Chief Executive Officer, Chief Financial Officer and principal accounting officer. The Code of Ethics is available for viewing on our website (http://www.pengrowth.com).
Since the adoption of its Code of Ethics, Pengrowth has not amended the code or granted any waivers (including implicit waivers) from the terms thereof.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table provides information about the aggregate fees billed to Pengrowth for professional services rendered by KPMG LLP during fiscal 2003 and 2002:
| 2003 | 2002 | |||||||
| Category | $M | $M | ||||||
| Audit Fees | $ | 253 | $ | 627 | ||||
| Audit Related Fees | nil | nil | ||||||
| Tax Fees | $ | 84 | $ | 427 | ||||
| All Other Fees | $ | 26 | nil | |||||
| Total | $ | 363 | $ | 1,054 | ||||
Audit Fees. Audit fees consist of fees for the audit of Pengrowth’s annual financial statements and services that are normally provided in connection with statutory and regulatory filings or engagements.
Audit-Related Fees. Audit-related fees normally include due diligence reviews in connection with acquisitions, research of accounting and audit-related issues, review of reserves disclosure and the completion of audits required by contracts to which Pengrowth is a party.
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Tax Fees. During 2003 and 2002 the services provided in this category included assistance and advice in relation to the preparation of income tax returns for Pengrowth Trust and its subsidiaries, tax advice and planning and commodity tax consultation.
All Other Fees. During 2003 the services provided in this category included consultation regarding the US Sarbanes Oxley Act and internal controls.
PRE-APPROVAL POLICIES AND PROCEDURES
Pengrowth has adopted the following policies and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by KPMG LLP: The audit committee approves a schedule which summarizes the services to be provided that the audit committee believes to be typical, recurring or otherwise likely to be provided by KPMG LLP. The schedule generally covers the period between the adoption of the schedule and the next meeting of the audit committee, but at the option of the audit committee, may cover a shorter or longer period. The list of services is sufficiently detailed as to the particular services to be provided to ensure that (i) the audit committee knows precisely what services it is being asked to pre-approve and (ii) it is not necessary for any member of Pengrowth’s management to make a judgment as to whether a proposed service fits within the pre-approved services.
Pengrowth has not approved any non-audit services on the basis of thede minimisexemptions. All non-audit services are pre-approved by the Audit Committee in accordance with the pre-approval policy referenced herein.
OFF-BALANCE SHEET ARRANGEMENTS
Pengrowth has no off-balance sheet arrangements.
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
The disclosure regarding the contractual obligations of Pengrowth under the heading “Commitments and Contractual Obligations” in the Management’s Discussion and Analysis appearing on page 59 of Pengrowth Trust’s 2003 annual report is incorporated by reference herein.
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE
The board of directors of Pengrowth complies with the Guidelines for effective Corporate Governance of the Toronto Stock Exchange (the “TSX”) and Pengrowth’s corporate governance practices in comparison with the TSX best practices are disclosed on pages 12 through 21 of Pengrowth’s Information Circular-Proxy Statement, which pages are incorporated by reference herein. These guidelines address the constitution of boards of directors and board committees as well as their functions, their independence from management and other means to promote sound Corporate Governance practices.
Pengrowth is also considering and preparing for the application of recent legislative changes in Canada and the recommendations of influential organizations and commentators on effective corporate governance. Multilateral Instrument 58-201 on effective Corporate Governance was published for comment by the Canadian Securities administrators (the “CSA”) and will be considered for implementation in 2005. The impact of Multilateral Instrument 52-110 in respect of audit committees, Multilateral Instrument 52-109 in respect of the certification of disclosure on issuers’ annual and interim filings and National Instrument 51-101 in respect of standards of disclosure for oil and gas activities are being considered by Pengrowth. These rules, as implemented and as proposed for implementation, are meant to align Canadian corporate governance with U.S. corporate governance, as set out in the Sarbanes-Oxley Act of 2002 and the Corporate Governance Listing Standards of the New York Stock Exchange. Further disclosure of Pengrowth’s corporate governance practices, is found on pages 100 through 102 of Pengrowth’s 2003 Annual Report, which pages are incorporated by reference herein.
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ADDITIONAL INFORMATION
Additional information, including Pengrowth Management’s remuneration and the principal holders of trust units, is contained in the Information Circular — Proxy Statement of Pengrowth Corporation and Pengrowth Trust dated March 15, 2004 and the Supplement thereto dated March 29, 2004, which relates to the Annual and Special Meeting of unitholders, and the Annual and Special Meeting of shareholders of Pengrowth Corporation and the Special Meeting of holders of royalty units to be held on April 22, 2004. Additional financial information is contained in Pengrowth Trust’s comparative financial statements for the years ended December 31, 2003 and 2002 which are included in Pengrowth Trust’s 2003 Annual Report.
Pengrowth Trust will provide to any person or company upon request:
| (a) | when the securities of Pengrowth Trust are in the course of a distribution pursuant to a short form prospectus or a preliminary short form prospectus has been filed in respect of a proposed distribution of its securities; |
| (i) | one copy of Pengrowth Trust’s latest annual information form, together with one copy of any document, or the pertinent pages of any document, incorporated therein by reference; |
| (ii) | one copy of the consolidated financial statements of Pengrowth Trust for the most recently completed financial year in respect of which such financial statements have been issued together with the report of the auditor thereon, and one copy of any unaudited interim consolidated financial statements of Pengrowth Trust subsequent to the financial statements for its most recent financial year; |
| (iii) | one copy of the information circular of Pengrowth Trust in respect of the most recent annual meeting of unitholders of Pengrowth Trust which involved the election of directors of Pengrowth Corporation; and |
| (iv) | one copy of any other documents which are incorporated by reference into the preliminary short form prospectus or the short form prospectus and are not required to be provided under (a) (i) to (iii) above; or |
| (b) | at any other time, a copy of the documents referred to in clauses (a) (i) to (iii) above, provided that Pengrowth Trust may require a payment of a reasonable charge from such a person or company who is not a unitholder. |
For additional copies of the Annual Information Form and the materials listed in the preceding paragraphs please contact:
| Calgary Head Office | Toronto Investor Relations | |
| Suite 2900, 111 — 5th Avenue S.W. | Suite 2315, 200 Bay Street | |
| Calgary, Alberta T2P 3Y6 | Toronto, Ontario M5J 2J2 | |
| Telephone: (403) 233-0224 | Telephone: (416) 362-1748 | |
| 1-800-223-4122 | 1-888-744-1111 | |
| Fax: (403) 294-0051 | Fax: (403) 362-8191 |
Website: www.pengrowth.com
email: pengrowth@pengrowth.com
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APPENDIX A
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REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
To the board of directors of Pengrowth Corporation (the “Company”):
We have prepared an evaluation of the Company’s reserves data as at December 31, 2003. The reserves data consist of the following:
| (a) (i) | proved and proved plus probable oil and gas reserves estimated as at December 31, 2003, using forecast prices and costs; and | |||
| (ii) | the related estimated future net revenue; and | |||
| (b) (i) | proved oil and gas reserves estimated as at December 31, 2003, using constant prices and costs; and | |||
| (ii) | the related estimated future net revenue. | |||
The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2003, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors:
| Description and Preparation Date of | Location of Reserves (Country or Foreign | Net Present Value of Future Net Revenue (before income taxes, 10% discount rate) | ||||||||||||||||||
| [Audit/Evaluation/ | Geographic | |||||||||||||||||||
| Review] Report | Area) | Audited | Evaluated | Reviewed | Total | |||||||||||||||
| January 30, 2004 | Canada | $ | 0 | $1604MM | $ | 0 | $1604MM | |||||||||||||
We have no responsibility to update this evaluation for events and circumstances occurring after the preparation date.
Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.
Gilbert Laustsen Jung Associates Ltd., Calgary, Alberta, Canada Dated February 19, 2004
ORIGINALLY SIGNED BY
Vice-President
A-1
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APPENDIX B
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FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
Management of Pengrowth Corporation (the “Company”) are responsible for the preparation and disclosure of information with respect to the oil and gas activities of Pengrowth Energy Trust (the “Pengrowth Trust”) in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:
| (a) | (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and |
| (ii) | the related estimated future net revenue; and |
| (b) | (i) proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and |
| (ii) | the related estimated future net revenue. |
An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.
The Reserves Committee of the board of directors of the Company has
| (a) | reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator; |
| (b) | met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and |
| (c) | reviewed the reserves data with management and the independent qualified reserves evaluator. |
The Reserves 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, on the recommendation of the Reserves Committee, approved
| (d) | the content and filing with securities regulatory authorities of the reserves data and other oil and gas information; |
| (e) | the filing of the report of the independent qualified reserves evaluator on the reserves data; and |
| (f) | the content and filing of this report. |
Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.
B-1
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/s/ James S. Kinnear
James S. Kinnear
Chairman, President and Chief Executive Officer
Pengrowth Corporation
/s/ Lynn Kis
Lynn Kis
Vice President, Engineering
Pengrowth Corporation
/s/ Stanley H. Wong
Stanley H. Wong
Director
Pengrowth Corporation
/s/ Thomas A. Cumming
Thomas A. Cumming
Director
Pengrowth Corporation
May 17, 2004
B-2
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APPENDIX B
MANAGEMENT’S DISCUSSION AND ANALYSIS (INCLUDED ON PAGES 42 THROUGH 65 OF THE PENGROWTH ENERGY TRUST 2003 ANNUAL REPORT)
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Management’s Discussion and Analysis
The following discussion and analysis of financial results should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2003 and is based on information available to February 29, 2004 except for the unit offering entered into on March 4, 2004 as discussed on page 58. Certain prior period comparative numbers included within this discussion and analysis have been restated to reflect the changes in accounting policies as discussed in Note 3 to the financial statements.
Note Regarding Forward-Looking Statements
This discussion and analysis contains forward-looking statements. These statements relate to future events or our future performance. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “should”, “expect”, “plan”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “continue”, or the negative of these terms or other
comparable terminology. These statements are only predictions. A number of factors, including the business risks discussed below, may cause actual results to vary materially from these estimates. Actual events or results may differ materially. In addition, this discussion contains forward-looking statements attributed to third-party industry sources. Readers should not place undue reliance on these forward-looking statements.
Critical Accounting Estimates
As discussed in Note 2 to the financial statements, the preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended.
The amounts recorded for depletion, depreciation and amortization of injectants and the provision for asset retirement obligations are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. As required by National Instrument 51-101 (NI 51-101), Pengrowth uses independent qualified reserve evaluators in the preparation of reserve evaluations. By their nature, these estimates are subject to measurement uncertainty and changes in these estimates may impact the consolidated financial statements of future periods.
Conversion and Currency
When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth has adopted the international standard of six thousand cubic feet (mcf) to one barrel of oil equivalent (boe). All amounts are stated in Canadian dollars unless otherwise specified.
42 Pengrowth Energy Trust · 2003 annual report
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Year 2003 Overview
Record high commodity prices in 2003, partially offset by a decline in the U.S. dollar relative to the Canadian dollar and increased production from the acquisition of producing properties in British Columbia in the fourth quarter of 2002, contributed to the strong performance by Pengrowth Energy Trust in 2003.
Highlights
| • | Oil and gas sales increased by 42 percent to a record $683 million in 2003 from $482 million in 2002. | |||
| • | Production increased by 12 percent to 49,033 boe per day in 2003 compared to 43,785 boe per day in 2002. | |||
| • | Pengrowth’s average realized commodity price increased by 26 percent to $38.15 per boe in 2003, the highest average realized price per boe in the history of the Trust. | |||
| • | On April 23, 2003 Pengrowth closed a US$200 million private debt placement, issuing U.S. $150 million 7-year and U.S. $50 million 10-year term notes at an average interest rate of 5.07 percent. As a result of the increase in the Canadian dollar relative to the U.S. dollar since April 2003, Pengrowth recorded an unrealized foreign exchange gain of $31 million on $U.S.-denominated debt. | |||
| • | During 2003 Pengrowth strengthened its financial position. Long-term debt was reduced to $259 million at the end of 2003 compared to $317 million at year-end 2002. The long-term debt to debt-plus-equity ratio was a conservative 0.2 times, and Pengrowth had $64 million of cash on the balance sheet at year-end. | |||
| • | On July 23, Pengrowth closed a public offering of 8.5 million trust units at $16.95 per unit to raise gross proceeds of $144 million (net equity proceeds of $136 million). These proceeds more than funded total acquisitions in the year of $123 million. | |||
Pengrowth Energy Trust · 2003 annual report 43
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| • | During 2003 Pengrowth acquired an 8.4 percent interest in the Sable Energy Offshore Project (SOEP) onshore and offshore facilities, certain significant discovery licences and converted its royalty interest into an 8.4 percent working interest in SOEP for a total purchase price of $127 million net of adjustments. As a result of these transactions, Pengrowth has eliminated the requirement to pay third-party processing fees for the SOEP facilities, which were approximately $30 million per year, prior to acquisition. | |||
| • | Operating costs increased marginally to $8.33 per boe in 2003 from $8.12 per boe in 2002, as a result of increasing costs in the industry, offset in part by reduced processing fees at SOEP following our acquisition of an interest in the SOEP onshore facilities in May 2003. | |||
| • | Pengrowth spent a total of $85.7 million on development projects in 2003. These expenditures were funded through the 10 percent holdback from distributions which commenced in January 2003, and equity proceeds received from the distribution reinvestment plan (DRIP) and the trust unit option and rights incentive plans. | |||
| • | Net income increased to $189 million in 2003 from $57 million in 2002. Included in 2003 net income is an unrealized foreign exchange gain of $31 million. | |||
| • | Cash distributions to unitholders totaled $313 million or $2.68 per trust unit, an increase of 29 percent from the $2.07 per unit paid to unitholders in 2002. | |||
| • | Year-end proved plus probable (P50) reserves declined by 30.4 million boe as compared to the established reserves reported at year-end 2002 including 17.9 million boe attributable to production and revisions as announced in a News Release on February 2, 2004. | |||
44 Pengrowth Energy Trust · 2003 annual report
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Financial and Operating Highlights
| (thousands, except per unit amounts) | Three Months ended December 31 | Twelve Months ended December 31 | ||||||||||||||||||||||
| % | % | |||||||||||||||||||||||
| 2003 | 2002 | Change | 2003 | 2002 | Change | |||||||||||||||||||
| Income Statement | ||||||||||||||||||||||||
| Oil and gas sales | $ | 152,077 | $ | 167,918 | (9 | ) | $ | 682,795 | $ | 482,301 | 42 | |||||||||||||
| Net income | $ | 37,355 | $ | 25,873 | 44 | $ | 189,297 | $ | 56,955 | 232 | ||||||||||||||
| Net income per unit | $ | 0.31 | $ | 0.25 | 24 | $ | 1.63 | $ | 0.63 | 159 | ||||||||||||||
| Distributable cash (1) | $ | 71,469 | $ | 67,060 | 7 | $ | 313,415 | $ | 194,458 | 61 | ||||||||||||||
| Actual distributions paid or declared per unit | $ | 0.63 | $ | 0.60 | 5 | $ | 2.68 | $ | 2.07 | 29 | ||||||||||||||
| Weighted average number of trust units outstanding | 122,326 | 102,209 | 20 | 115,912 | 89,923 | 29 | ||||||||||||||||||
| Balance Sheet | ||||||||||||||||||||||||
| Working capital | $ | 12,966 | $ | (36,568 | ) | 135 | ||||||||||||||||||
| Property, plant and equipment and other assets | $ | 1,530,359 | $ | 1,493,047 | 2 | |||||||||||||||||||
| Long-term debt | $ | 259,300 | $ | 316,501 | (18 | ) | ||||||||||||||||||
| Unitholders’ equity | $ | 1,159,433 | $ | 1,073,164 | 8 | |||||||||||||||||||
| Unitholders’ equity per unit | $ | 9.36 | $ | 9.71 | (4 | ) | ||||||||||||||||||
| Number of units outstanding at year-end | 123,874 | 110,562 | 12 | |||||||||||||||||||||
| Daily Production | ||||||||||||||||||||||||
| Crude oil (barrels) | 22,193 | 25,358 | (12 | ) | 23,337 | 19,914 | 17 | |||||||||||||||||
| Natural gas (thousands of cubic feet) | 117,315 | 127,391 | (8 | ) | 119,842 | 111,713 | 7 | |||||||||||||||||
| Natural gas liquids (barrels) | 5,907 | 5,664 | 4 | 5,722 | 5,252 | 9 | ||||||||||||||||||
| Total production (boe) (6:1) | 47,653 | 52,253 | (9 | ) | 49,033 | 43,785 | 12 | |||||||||||||||||
| Change in production (year over year) (%) | (9 | ) | 18 | 12 | 9 | |||||||||||||||||||
| Production Profile (6:1 conversion) (%) | ||||||||||||||||||||||||
| Crude oil | 47 | 48 | 47 | 45 | ||||||||||||||||||||
| Natural gas | 41 | 41 | 41 | 43 | ||||||||||||||||||||
| Natural gas liquids | 12 | 11 | 12 | 12 | ||||||||||||||||||||
| Average Prices | ||||||||||||||||||||||||
| Crude oil (per barrel) | $ | 38.08 | $ | 39.91 | (5 | ) | $ | 40.64 | $ | 38.06 | 7 | |||||||||||||
| Natural gas (per mcf) | $ | 5.36 | $ | 5.16 | 4 | $ | 6.21 | $ | 3.85 | 61 | ||||||||||||||
| Natural gas liquids (per barrel) | $ | 35.45 | $ | 30.78 | 15 | $ | 35.46 | $ | 28.11 | 26 | ||||||||||||||
| Average price per boe (6:1) | $ | 34.69 | $ | 34.93 | (1 | ) | $ | 38.15 | $ | 30.18 | 26 | |||||||||||||
| Proved plus Probable (P50) Reserves (2) | ||||||||||||||||||||||||
| Crude oil (mbbls) | 97,360 | 106,738 | (9 | ) | ||||||||||||||||||||
| Natural gas (bcf) | 412.8 | 502.3 | (18 | ) | ||||||||||||||||||||
| Natural gas liquids (mbbls) | 18,250 | 24,354 | (25 | ) | ||||||||||||||||||||
| Total oil equivalent (mboe) | 184,416 | 214,814 | (14 | ) | ||||||||||||||||||||
(1) See Note 4 to the Financial Statements.
(2) For 2002, Reserves were Established Reserves which are equivalent to Proved Plus Probable (P50) Reserves as reported in 2003.
Pengrowth Energy Trust · 2003 annual report 45
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Results Of Operations
Production
Average daily production increased by 12 percent to 49,033 boe per day in 2003 compared to 43,785 boe per day in 2002. This increase is mainly attributable to the acquisition of Calpine Canada’s British Columbia properties on October 1, 2002 and development activities at some other Pengrowth properties which partially offset normal production declines. The 2003 fourth-quarter production of 47,653 boe per day was 9 percent lower than 2002 fourth quarter production of 52,253 boe per day, reflecting the production decline over this period, offset in part by development activities and minor acquisition volumes. Production from the SOEP Alma field, which came onstream at the end of November 2003, and incremental gas volumes from new wells drilled at Cessford and Dunvegan near year-end 2003, should have a positive impact on first-quarter 2004 production. At this time, Pengrowth is forecasting average 2004 production of approximately 44,000 to 45,000 boe per day from our existing properties.
46 Pengrowth Energy Trust • 2003 annual report
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Daily Production Volumes
| 2003 | 2002 | % Change | ||||||||||
| Crude oil (bbl) | 23,337 | 19,914 | 17 | |||||||||
| Natural gas (mcf) | 119,842 | 111,713 | 7 | |||||||||
| Natural gas liquids (bbl) | 5,722 | 5,252 | 9 | |||||||||
| Total daily sales volumes (boe) | 49,033 | 43,785 | 12 | |||||||||
Pricing and Commodity Price Hedging
The increase in U.S.-based prices for North American crude oil and natural gas were partially offset by the negative impact of the rising Canadian dollar relative to the U.S. dollar. Pengrowth’s average realized commodity price for 2003 was the highest for any year since the inception of the Trust.
Benchmark Pricing
| 2003 | 2002 | % Change | ||||||||||
| WTI crude oil ($ U.S./bbl) | $ | 30.99 | $ | 26.08 | 19 | |||||||
| AECO (monthly) natural gas ($/mcf) | $ | 6.70 | $ | 4.07 | 65 | |||||||
| NYMEX (HH close) natural gas ($U.S./mmbtu) | $ | 5.39 | $ | 3.22 | 67 | |||||||
| Currency ($Cdn/$U.S.) | $ | 0.7136 | $ | 0.6368 | 12 | |||||||
Pengrowth Energy Trust • 2003 annual report 47
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Pengrowth’s Average Realized Prices
(Adjusted for Hedging)
| 2003 | 2002 | % Change | ||||||||||
| Crude oil ($/bbl) | $ | 40.64 | $ | 38.06 | 7 | |||||||
| Natural gas ($/mcf) | $ | 6.21 | $ | 3.85 | 61 | |||||||
| Natural gas liquids ($/bbl) | $ | 35.46 | $ | 28.11 | 26 | |||||||
| Total oil and gas sales ($/boe) | $ | 38.15 | $ | 30.18 | 26 | |||||||
Pengrowth’s average crude oil price increased by 7 percent in 2003 to $40.64 per barrel compared to $38.06 per barrel in 2002. Although the 2003 average WTI benchmark crude price increased by 19 percent to $31.02 per barrel in 2003, much of this increase was offset by the decline in the U.S. dollar relative to the Canadian dollar.
In 2003 Pengrowth had 10,838 barrels per day, or 46 percent of crude oil production hedged at an average price of Cdn $41.41 per barrel. Pengrowth’s hedging program resulted in a total hedging loss on crude oil for the year of $7.8 million or $0.92 per barrel, compared to a loss of $6.1 million or $0.83 per barrel in 2002.
Pengrowth’s average natural gas price increased by 61 percent from $3.85 per mcf in 2002 to $6.21 per mcf in 2003. In comparison, the average AECO and NYMEX benchmark gas prices increased by 65 percent and 67 percent respectively.
Pengrowth sold a total of 30.4 mmcf per day or approximately 26 percent of 2003 natural gas production under fixed price or financial swap contracts at an average price of $6.60 per mcf. The Trust realized a net hedging loss of $16.0 million, or $0.37 per mcf in 2003, compared to a net loss of $1.8 million or $0.04 per mcf in 2002.
Pengrowth’s average price for natural gas liquids (NGLs) increased by 26 percent to $35.46 in 2003 compared to $28.11 in 2002. Approximately one-third of Pengrowth’s NGL production is condensate and pentane for which market prices are impacted more by the price of crude. Prices for propane, butane and ethane, which comprise the balance of Pengrowth’s NGLs, track natural gas prices more closely.
Oil and Gas Sales
Oil and Gas Sales
| ($ millions) | 2003 | 2002 | % Change | |||||||||
| Crude oil | $ | 346.2 | $ | 276.6 | 25 | |||||||
| Natural gas | 271.6 | 156.9 | 73 | |||||||||
| Natural gas liquids | 74.1 | 53.9 | 37 | |||||||||
| Less: gross overriding royalties | (11.7 | ) | (8.2 | ) | 43 | |||||||
| Gas marketing and brokering income, sulphur | 2.6 | 3.1 | (16 | ) | ||||||||
| Total oil and gas sales | $ | 682.8 | $ | 482.3 | 42 | |||||||
48 Pengrowth Energy Trust • 2003 annual report
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As a result of the 12 percent increase in production volumes and the 26 percent increase in the average realized price per boe, as previously discussed, Pengrowth’s total oil and gas sales reported in 2003 increased by 42 percent to $682.8 million. The following table illustrates in detail the effect of changes in prices and volumes on the components of oil and gas sales.
Oil and Gas Sales – Price and Volume Analysis
| ($ millions) | Oil | Gas | NGL | GORR | Other | Total | ||||||||||||||||||
| Year ended December 31, 2002 | $ | 276.6 | $ | 156.9 | $ | 53.9 | $ | (8.2 | ) | $ | 3.1 | $ | 482.3 | |||||||||||
| Effect of increase in sales volumes | 47.6 | 11.4 | 4.8 | – | – | 63.8 | ||||||||||||||||||
| Effect of increase in product prices | 22.0 | 103.3 | 15.4 | – | – | 140.7 | ||||||||||||||||||
| Other | – | – | – | (3.5 | ) | (0.5 | ) | (4.0 | ) | |||||||||||||||
| Year end December 31, 2003 | $ | 346.2 | $ | 271.6 | $ | 74.1 | $ | (11.7 | ) | $ | 2.6 | $ | 682.8 | |||||||||||
Royalties
Crown royalties, net of incentives and freehold royalties and mineral taxes increased to $114.9 million in 2003 from $80.6 million in 2002. Royalties as a percentage of oil and gas sales were consistent with 2002 at 17 percent. Although the effective royalty rate was somewhat higher for most properties in 2003 due to higher commodity prices, particularly natural gas, this increase was offset by increased injection credits at Judy Creek as a result of higher miscible flood injection costs.
Operating Expenses
Operating expenses increased to $149.0 million in 2003 compared to $129.8 million in 2002, mainly as a result of the British Columbia properties acquired in the fourth quarter of 2002. This was somewhat offset by a reduction of SOEP processing fees, following the acquisition of an interest in the facilities downstream of the Thebaud Central Platform in May 2003.
Operating costs per boe increased by 3 percent to $8.33 per boe compared to $8.12 per boe in 2002. Higher electricity rates in 2003, an increase in CO2 costs at Weyburn, general cost increases in the industry, and production declines contributed to higher operating costs per boe in 2003. This was despite cost savings on processing fees of approximately $9.5 million realized as a result of the purchase of the SOEP onshore facilities. The 2003 fourth-quarter operating costs were $3.0 million lower than the fourth quarter of 2002, due to the reduction of SOEP processing fees in 2003 and some additional costs incurred in the last quarter of 2002. Fourth-quarter 2003 operating expenses were $3.2 million higher than the third quarter of 2003, due to a number of factors including additional well workover costs on operated properties, prior period adjustments billed by other operators on non-operated properties, and lower casinghead revenues (which is netted against operating expenses at Judy Creek).
At this time, based on our current property portfolio, Pengrowth’s total operating costs are expected to decline by approximately $10-$15 million in 2004. This reduction is anticipated as a result of decreased processing fees at SOEP due to the purchase of the SOEP offshore facilities at the end of December 2003, and the SOEP on-shore facilities in May 2003, offset in part by
Pengrowth Energy Trust • 2003 annual report 49
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higher costs at some of our other properties and general cost increases. If we continue to see strong market prices for commodities, there is likely to be continued upward pressure on operating costs, due to factors such as increased demand for skilled industry workers as companies expand exploration and development projects, higher fuel costs and higher electricity rates. In order to help mitigate the risk of higher electricity rates, Pengrowth has fixed the price on approximately 20 percent of our estimated electricity requirements at operated properties in 2004.
Amortization of Injectants for Miscible Floods
The cost of injectants (primarily ethane and methane) purchased for injection in miscible flood programs is amortized over the period of expected future economic benefit, which is estimated at 30 months. In 2003, the total cost of products purchased for reinjection increased to $23.0 million in 2003 from $15.1 million in 2002. Pengrowth amortized and deducted $32.5 million of injectant costs from distributable cash in 2003 (2002 – $44.3 million). As at December 31, 2003 Pengrowth had deferred injectant costs of $24.3 million which will be amortized and charged against distributable cash of future periods.
The value of Pengrowth’s proprietary injectants is not recorded until reproduced from the flood and sold, although the cost of producing these products for reinjection is included in operating costs. Total injectant costs are expected to increase in 2004 due to higher forecasted prices for natural gas and ethane and increased activity at the Swan Hills flood. The amount of injectants amortized against distributable cash is expected to decline in 2004 as the deferred portion of prior years’ costs has declined.
Interest
Pengrowth’s average long-term debt was marginally lower in 2003 compared to 2002. However, interest expense increased to $18.2 million in 2003 from $15.2 million in 2002, reflecting a higher average interest rate on the term debt issued in 2003 compared to floating rates on bank debt in 2002. Included in interest expense in 2003 is $2.2 million related to the cancellation of interest rate swaps after all of Pengrowth’s floating rate debt was either replaced with fixed-rate term debt in April 2003, or repaid with the July 2003 equity proceeds.
The average interest rate on all of Pengrowth’s long-term debt outstanding at December 31, 2003 is 5.07 percent and is payable in U.S. dollars and therefore subject to fluctuations in the exchange rate. The Note Payable is non-interest bearing.
Foreign Currency Gains and Losses
Pengrowth recorded a net foreign exchange gain of $29.9 million in 2003 compared to a foreign exchange loss of $0.2 million in 2002. Included in the 2003 net gain of $29.9 million is $30.9 million of unrealized foreign exchange gain related to the U.S. dollar-denominated debt. This arises as a result of the increase in the Canadian dollar since the debt was issued in April 2003, from a rate of approximately $0.69 to $0.77 at year-end. The balance, a foreign exchange loss of $1.0 million, relates mainly to U.S. dollar-denominated natural gas sales from SOEP. Pengrowth
50 Pengrowth Energy Trust · 2003 annual report
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has hedged the exchange rate on a portion of these U.S.-denominated gas sales. Revenues are recorded at the average exchange rate for the production month in which they accrue, with payment being received on or about the 25th of the month following production. As a result of the increase in the Canadian dollar relative to the U.S. dollar over the course of the year, a foreign exchange loss was recorded to the extent of the differential between the average exchange rate for the month of production and the exchange rate at the date the payments were received on unhedged gas sales.
General and Administrative
General and administrative expenses (G&A) increased to $16.0 million ($0.89 per boe) from $11.0 million ($0.69 per boe) in 2002. G&A costs have increased in 2003 due to a number of factors including an increase in office rent and staffing levels following the acquisition of Calpine’s British Columbia properties in October 2002, and additional costs of administering an expanding unitholder base. Legal and regulatory costs have also increased as a result of listing on the New York Stock Exchange in the second quarter of 2002 and recent changes to regulatory requirements arising from the Sarbanes-Oxley Act and similar new or proposed legislation in Canada. Included in 2003 G&A is $0.2 million in non-cash compensation expense related to the estimated fair value of trust unit rights granted in 2003. (See Note 3 and Note 11 to the Financial Statements for details).
Management Fees
Management fees paid to Pengrowth Management Limited (the Manager) increased to $10.2 million in 2003 from $6.6 million in 2002. Although the management fee rate decreased effective July 1, 2003 there is an increase in total management fees due to the growth in the size of the business and net operating income as management fees are calculated on a percentage of “net operating income” (oil and gas sales and other income, less royalties, operating costs, solvent amortization and reclamation funding).
A new management agreement, which was approved at the annual general meeting on June 17, 2003 was effective July 1, 2003. Under the terms of this agreement, the base fee has been reduced from a sliding scale between 3.5 percent and 2.5 percent, to 2 percent on the first $200 million of net operating income and 1 percent on net operating income over $200 million for the first three-year term; acquisition fees have been eliminated, and the manager will receive a ‘performance fee’ if certain performance criteria are met — in particular should returns exceed 8 percent per annum on a three-year rolling-average basis. The maximum fees, including the performance fee, is limited to 80 percent of the fees that would otherwise have been paid under the old management agreement (including acquisition fees) for the first three years, and 60 percent for the second three years. Management fees for 2003 include a performance fee of $520,000, which represents 80 percent of the amount that would have been earned as an ‘acquisition fee’ under the old agreement, and together with the base fee for the second half of 2003, is equivalent to 80 percent of total fees that would have been earned by the Manager for that period.
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Related Party Transactions
Details of related party transactions incurred in 2003 and 2002 are provided in Note 16 to the financial statements. These transactions include the Management fees paid to the Manager, as discussed in the preceding paragraphs. The Manager is controlled by James S. Kinnear, the Chairman, President and Chief Executive officer of Pengrowth Corporation. As discussed above, the management fees paid to the Manager are pursuant to a management agreement which has been approved by the Trust unitholders. Mr. Kinnear is not entitled to receive any salary or bonus in his capacity as a director and officer of Pengrowth Corporation.
Related party transactions in 2003 also include $675,692 paid to a firm controlled by the Corporate Secretary of Pengrowth Corporation, Mr. Charles V. Selby. These fees are paid in respect of legal and advisory services provided by the Corporate Secretary.
Taxes
In determining its taxable income, Pengrowth Corporation deducts royalty payments to unitholders and historically, this has been sufficient to reduce taxable income to nil. The recent change to Pengrowth’s distribution approach, whereby approximately 10 percent of funds available for distribution are withheld to fund future capital expenditures, could result in taxable income in the Corporation in the future. However, there are at present sufficient tax pools available in the Corporation to offset the expected level of income to be retained.
Capital taxes of $1.8 million in 2003 (2002 — $0.5 million) consists of Federal Large Corporations Tax (LCT) of $0.6 million and $1.2 million Saskatchewan Capital Tax and Resource Surcharge. Included in the amount recorded in 2002 is a LCT recovery of $1.3 million related to prior year reassessments. Under new federal tax legislation passed in 2003 and commencing in 2004, the taxable capital threshold will increase to $50 million and the LCT rate will gradually decline and be eliminated completely by 2008.
Depletion and Depreciation
Depletion and depreciation of property, plant and equipment and other assets is provided on the unit-of-production method based on total proved reserves. The provision for depletion and depreciation increased by 32 percent in 2003 to $185.3 million from $140.8 million in 2002 due to a larger depletable asset base and higher depletion rate (production as a percentage of total proved reserves). On a unit-of-production basis, depletion increased by 17 percent to $10.35 per boe in 2003 from $8.81 per boe in 2002. The retroactive application of the new accounting policy for asset retirement obligations required restatement of prior periods and this resulted in an increase in the 2002 depletion and depreciation rate to $8.81 per boe from $8.69 per boe. The increase in the per boe depletion amount in 2003 reflects the acquisition of the SOEP facilities in 2003 without any associated reserves. With respect to the fourth-quarter depletion provision, the increase also reflects the reduction in total proved reserves recognized at year-end, which increases the depletion rate.
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Ceiling Test
In 2003 Pengrowth adopted AcG-16 “Oil and Gas Accounting — Full Cost” a new CICA guideline which replaces AcG-5 “Full Cost Accounting in the Oil and Gas Industry”. AcG-16 includes changes to the way the ceiling test must be calculated, the details of which are provided in Note 2 to the financial statements. Implementation of this guideline had no impact on Pengrowth’s 2003 financial results.
Asset Retirement Obligations
In 2003, the CICA issued Section 3110, “Asset Retirement Obligations” which harmonizes Canadian GAAP requirements with the corresponding U.S. GAAP requirements under SFAS 143. Under these standards, the fair value of a liability for asset retirement obligations must be recognized in the period in which it is incurred, and a corresponding asset retirement cost is to be added to the carrying amount of the related asset. The new Canadian standard is effective for fiscal years beginning on or after January 1, 2004 with earlier adoption encouraged. Pengrowth has elected to implement this standard in 2003. As a result of implementation, the liability for future site restoration costs (now called “asset retirement obligations” under the new standard) increased by $41 million and property, plant and equipment net of accumulated depletion increased by $70 million as at December 31, 2003. Opening 2003 unitholders’ equity increased by $19 million to reflect the cumulative impact of accretion and depletion expense, net of the cumulative change to the site restoration provision.
Under the previous accounting method for future site restoration costs, the provision for future site restoration costs was made over the life of the oil and gas properties and facilities using the unit-of-production method. Accretion, as recorded under the new Section 3110, represents the change in the discounted value of the liability due to the passage of time.
Remediation Trust Funds and Remediation and Abandonment Expenses
Pursuant to the purchase of the Judy Creek and Swan Hills properties from Imperial Oil Resources in 1997, Pengrowth established a trust fund to fund certain obligations of these properties. Following the acquisition of a working interest in the SOEP facilities in 2003, Pengrowth has also contributed to a trust fund in respect to the future remediation costs of these facilities.
Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations on operated properties. Operations personnel have completed a detailed analysis of expected future site restoration and abandonment costs for all of the major operated properties. Pengrowth expects to spend approximately $6 million per year over the next 10 years on remediation and abandonment expenses at operated properties.
Netbacks
Pengrowth recorded an operating netback of $22.17 per boe in 2003 compared to $14.70 in 2002, mainly due to higher average commodity prices in 2003. For the fourth quarter of 2003 the operating netback of $20.43 was higher than the fourth quarter of 2002, mainly due to lower royalties and amortization of injectants.
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Operating Netback per Boe
| Three months | Year ended | |||||||||||||||
| ended December 31 | December 31, | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
| Oil and gas sales | $ | 34.69 | $ | 34.93 | $ | 38.15 | $ | 30.18 | ||||||||
| Crown and freehold royalties | (4.60 | ) | (7.05 | ) | (6.42 | ) | (5.04 | ) | ||||||||
| Other income | 0.63 | 0.48 | 0.59 | 0.45 | ||||||||||||
| Operating costs | (8.91 | ) | (8.74 | ) | (8.33 | ) | (8.12 | ) | ||||||||
| Amortization of injectants | (1.38 | ) | (2.12 | ) | (1.82 | ) | (2.77 | ) | ||||||||
| Operating netback | $ | 20.43 | $ | 17.50 | $ | 22.17 | $ | 14.70 | ||||||||
Distributions and Taxability of Distributions
Pengrowth paid $313.4 million ($2.68 per unit) in distributions related to 2003 cash flow, compared to $194.5 million ($2.07 per unit) in 2002. This equates to 88 percent of funds generated from operations, compared to 85 percent in 2002.
Commencing with the January 15, 2003 distribution to unitholders, approximately 10 percent of cash available for distribution has been withheld to fund capital expenditures as well as to stabilize monthly distributions. Subject to a limit of 20 percent of gross revenues, as approved by unitholders at the 2002 annual general meeting, the Board of Directors may decide to increase (or decrease) the amount withheld in the future, depending on a number of factors. These include future commodity prices, capital expenditures requirements, and the availability of debt and equity capital.
Cash distributions are paid to unitholders on the 15th of the second month following the month of production. Pengrowth paid $2.66 per unit as cash distributions during the 2003 calendar year. For Canadian tax purposes 55.23 percent of these distributions or $1.4692 per unit is taxable income to unitholders for the 2003 tax year. The remaining 44.77 percent or $1.1908 per unit is a tax-deferred return of capital which will reduce the unitholder’s cost base of the unit for purposes of calculating a capital gain or loss upon ultimate disposition of the trust units.
At December 31, 2003 the Trust had unused tax deductions of $10.13 per unit (2002 — $10.64 per unit). At this time, Pengrowth anticipates that approximately 55 to 60 percent of 2004 distributions will be taxable; this estimate is subject to change depending on a number of factors including, but not limited to, the level of commodity prices, acquisitions, dispositions, and new equity offerings.
Non-Resident Ownership
Pengrowth’s ability to continue to qualify as a mutual fund trust is dependent on both the interpretation of theIncome Tax Act(Canada) and its level of foreign ownership. The latest ownership report received by Pengrowth dated effective January 31, 2004 indicated that foreign ownership of trust units was less than but approaching 50 percent. The level of foreign ownership of Pengrowth trust units has increased steadily since trust units were listed on the
54 Pengrowth Energy Trust • 2003 annual report
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New York Stock Exchange during April 2002 and following the cross-border equity offering of Pengrowth trust units completed in November 2002. Unitholder approval will be sought at Pengrowth’s Annual General Meeting for amendments to Pengrowth’s trust indenture and other constating documents that will enable the trust to manage foreign ownership levels and continue to maintain the trust primarily for the benefit of Canadian residents while encouraging orderly markets for trust units in Canada and the United States.
Acquisitions and Dispositions
On May 8, 2003 Pengrowth acquired an 8.4 percent working interest in the SOEP natural gas processing facilities downstream of the Thebaud Central Processing Platform for a net purchase price of $57 million. On December 31, 2003 Pengrowth acquired an 8.4 percent working interest in the SOEP offshore platforms and associated sub-sea field gathering lines from Emera Offshore Incorporated (Emera) and exchanged the royalty interest previously held for a working interest in the SOEP reserves, for a total purchase price of $65 million. As a result of these two transactions, Pengrowth now holds an 8.4 percent working interest in the entire SOEP project. In addition, in June of 2003 Pengrowth acquired interests in 11 significant discovery licenses (SDLs) related to potential future offshore Nova Scotia resources, for $4.5 million.
Capital Expenditures
Pengrowth spent $85.7 million in capital expenditures in 2003 compared to $55.6 million in 2002. In 2004, Pengrowth expects to spend approximately $135 million on development opportunities at our existing properties. The majority of this will be spent at Judy Creek, Monogram and SOEP.
Capital Expenditures
| Year ended December 31 | 2003 | 2002 | ||||||||||||||
| ($ millions) | Development | Total Capital | Total Capital | |||||||||||||
| Property | Drilling | Facilities | Expenditures | Expenditures | ||||||||||||
| Judy Creek | $ | 20.3 | $ | 1.2 | $ | 21.5 | $ | 20.8 | ||||||||
| SOEP | 13.7 | 1.3 | 15.0 | 14.2 | ||||||||||||
| Weyburn | 5.4 | 3.3 | 8.7 | 2.2 | ||||||||||||
| Cessford | 6.2 | 1.0 | 7.2 | – | ||||||||||||
| Oak | 4.1 | 2.0 | 6.1 | 0.1 | ||||||||||||
| McLeod River | 5.6 | 0.4 | 6.0 | 5.1 | ||||||||||||
| House Mountain | 2.7 | 0.1 | 2.8 | 1.7 | ||||||||||||
| Elm | 2.4 | – | 2.4 | – | ||||||||||||
| Tupper | 1.7 | 0.1 | 1.8 | – | ||||||||||||
| Other | 9.9 | 4.3 | 14.2 | 11.5 | ||||||||||||
| Total | $ | 72.0 | $ | 13.7 | $ | 85.7 | $ | 55.6 | ||||||||
Pengrowth Energy Trust • 2003 annual report 55
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Review of Development Activities
Operated Properties
At Judy Creek, 2003 development activity included four producing oil wells, two vertical water injection wells, one horizontal miscible injection well and two shallow gas wells. The 2004 development plan for Judy Creek includes four horizontal miscible injection wells, up to three oil wells in Judy “A” Pool, and up to three shallow gas wells.
At McLeod River, Pengrowth drilled a total of eight (4.9 net) wells in 2003—three of which are producing natural gas wells, one is awaiting tie-in, and the remaining four are currently under evaluation. The 2004 development plan at McLeod River includes 13 (7.2 net) new natural gas wells.
In 2003, Pengrowth drilled 10 (7.4 net) wells in northeast British Columbia. In addition, Pengrowth completed 23 additional farm-out transactions in 2003 on higher-risk development lands. These transactions have resulted in 14 new wells drilled and commitments for the drilling of 13 additional wells in 2004. Pengrowth holds gross overriding royalty interests in these farm-out lands—ranging from 0.5 to 15 percent. Approximately $17 million of Pengrowth’s 2004 capital budget will target further development opportunities at the British Columbia properties.
Non-operated Properties
At the Sable Offshore Energy Project (SOEP), where Pengrowth now holds an 8.4 percent working interest, the major milestone for 2003 was the successful start-up of Alma, the first Tier II field. The Alma platform is located in 67 metres of water and is connected to the SOEP Thebaud central processing platform via a 52-kilometre sub-sea pipeline. The Alma field is currently producing approximately 120 mmcf per day of natural gas and 3,000 barrels per day of condensate and natural gas liquids. With the addition of Alma, average daily production from the SOEP is approximately 500 mmcf per day of natural gas and 20,000 barrels per day of associated condensate and natural gas liquids. Natural declines in production are expected to be supplemented by production from South Venture when production starts in late 2004 and the installation of compression in 2006/2007.
SOEP activity for 2004 will be concentrated on the development of South Venture, SOEP compression and future field development.
At the Dunvegan Gas Unit, where Pengrowth holds a 7.98 percent working interest, the operator drilled 13 successful gas wells during the latter part of 2003. The wells are anticipated to commence production at an average gross rate of 1.0 mmcf per day per well. Three wells from the 2003 program were carried over and were drilled in January and 14 existing producers were also recompleted in 2003 with an average anticipated gross incremental rate of 250 mcf per day per well. The operator plans to drill an additional 24 wells and recomplete 12 existing producers in 2004.
At the Monogram Gas Unit, where Pengrowth holds a 53.82 percent working interest, 2004 plans include an extensive infill drilling program of approximately 150 wells as well as facility upgrades such as line looping and additional compression.
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At Swan Hills Unit #1, three successful wells were drilled in the fourth quarter of 2003 and up to five additional wells are planned for 2004. Other major 2004 projects include a CO2 pilot and additional miscible pattern development. Pengrowth has a 10.45 percent working interest in this unit.
At the Weyburn Unit, where Pengrowth has a 9.75 percent working interest, there are now 32 active CO2 patterns and the operator has proposed to develop an additional 10 patterns in 2004.
At Cessford, Pengrowth participated in a 73 well shallow gas program and also drilled eight operated wells in the fourth quarter of 2003. Prior to the infill program Pengrowth’s working-interest share of production was approximately 650 mcf per day and production had tripled as of year-end. Pengrowth holds a 60 percent working interest in the 73 non-operated wells and an 87.5 percent working interest in the eight operated wells.
Reserves
Pengrowth is now required to comply with National Instrument 51-101, issued by the Canadian Securities Administrators, in all its reserves-related disclosures. NI 51-101 came into effect on September 30, 2003 and is applicable for financial years ended on or after December 31, 2003. NI 51-101 brought about significant changes in which reporting issuers manage and publicly disclose information relating to their oil and natural gas reserves, mandates annual disclosure requirements and prescribes new reserve definitions.
Pengrowth reported year-end Proved plus Probable (P50) reserves of 184.4 million boe compared to 214.8 million boe of Established reserves reported at year-end 2002. Most of the decline of 30.4 million boe relates to 2003 production of 17.9 million boe and year-end revisions to SOEP reserves, as previously reported by Pengrowth in a news release on February 2, 2004. Further details of Pengrowth’s 2003 year-end reserves are provided on pages 36-38 of this annual report.
Financial Resources and Liquidity
In 2003, Pengrowth continued its policy of maintaining a conservative capital structure, capitalizing on opportunities to issue new equity when appropriate, while maintaining a high distribution pay-out ratio to unitholders. At year-end 2003, Pengrowth was in a strong financial position, with long-term debt to long-term debt-plus-equity ratio of 18 percent. Pengrowth has $235 million in committed credit facilities which is currently reduced by $22 million in letters of credit (reduced from $47 million outstanding at year-end 2003). With additional cash and term deposits of $64 million, Pengrowth is well positioned to fund its 2004 development program of $135 million, and to take advantage of acquisition opportunities as they arise.
In 2003, Pengrowth raised a total of $210.2 million net proceeds from new equity—$136.3 million net equity proceeds from an equity issue in July, with the balance coming from the employee trust unit option and trust unit rights plans, and the distribution reinvestment plan.
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On March 4, 2004 Pengrowth entered into an agreement to sell 8.2 million trust units at $18.40 per trust unit to raise gross proceeds of $150.9 million on a bought-deal basis. Pengrowth has granted the underwriters an option to purchase up to an additional 2.7 million trust units at the same offering price.
Pengrowth’s long-term debt at December 31, 2003 was fixed-rate term debt denominated in U.S. dollars and translated to $259 million. Due to the increase in the $Cdn/$U.S. exchange rate in 2003, an unrealized gain of $31 million has been recorded since the U.S. dollar-denominated debt was issued in April 2003.
Pengrowth’s long-term debt decreased by $58 million in fiscal 2003 to $259 million at year-end 2003. The factors contributing to the change in long-term debt are shown in the following table:
Continuity of Long-term Debt
| ($ millions) | 2003 | 2002 | ||||||
| Beginning balance, January 1 | $ | 317 | $ | 345 | ||||
| Less: Cash provided by operating activities | (347 | ) | (229 | ) | ||||
| Net equity proceeds | (210 | ) | (382 | ) | ||||
| Note payable | (45 | ) | – | |||||
| Unrealized foreign exchange gain | (31 | ) | – | |||||
| Property dispositions | (3 | ) | (43 | ) | ||||
| Add: Distributions | 307 | 171 | ||||||
| Property acquisitions | 123 | 392 | ||||||
| Capital expenditures | 86 | 56 | ||||||
| Increase in cash and term deposits | 56 | 4 | ||||||
| Other | 6 | 3 | ||||||
| Ending balance, December 31 | $ | 259 | $ | 317 | ||||
At December 31, 2003 Pengrowth also had a $45 million non-interest-bearing note payable to Emera Offshore Incorporated related to installments due upon the purchase of the SOEP offshore facilities from Emera on December 31, 2003. The terms of this note are provided in Note 9 to the financial statements.
At December 31, 2003 Pengrowth had cash and term deposits of $64 million, which are available to fund future capital expenditures and/or future acquisitions.
Financial Leverage and Coverage
| 2003 | 2002 | |||||||
| Distributable cash to interest expense (times) | 17 | 12 | ||||||
| Long-term debt to distributable cash (times) | 0.8 | 1.6 | ||||||
| Long-term debt to long-term debt-plus-equity (%) | 18 | 23 | ||||||
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Commitments and Contractual Obligations
| Less than | After | |||||||||||||||||||
| ($ thousands) | Total | 1 year | 1-3 years | 4-5 years | 5 years | |||||||||||||||
Long-term debt(1) | $ | 259,300 | $ | – | $ | – | $ | – | $ | 259,300 | ||||||||||
Interest payments on long-term debt(2) | 93,505 | 13,134 | 39,402 | 26,268 | 14,701 | |||||||||||||||
| Note payable | 45,000 | 10,000 | 35,000 | – | – | |||||||||||||||
| Operating leases | ||||||||||||||||||||
| Office rent | 1,679 | 697 | 982 | – | – | |||||||||||||||
| Vehicle leases | 1,966 | 519 | 1,282 | 165 | – | |||||||||||||||
| 3,645 | 1,216 | 2,264 | 165 | – | ||||||||||||||||
| Purchase obligations | ||||||||||||||||||||
| Pipeline transportation | 128,814 | 24,041 | 66,282 | 37,915 | 576 | |||||||||||||||
| Capital expenditures | 82,303 | 46,242 | 36,061 | – | – | |||||||||||||||
CO2 purchases | 57,508 | 5,372 | 17,089 | 9,341 | 25,706 | |||||||||||||||
| Electricity commitment | 2,130 | 2,130 | – | – | – | |||||||||||||||
| 270,755 | 77,785 | 119,432 | 47,256 | 26,282 | ||||||||||||||||
Remediation trust fund payments(3) | 1,250 | 250 | 750 | 250 | – | |||||||||||||||
| Total | $ | 673,455 | $ | 102,385 | $ | 196,848 | $ | 73,939 | $ | 300,283 | ||||||||||
| (1) | U.S. dollar-denominated debt due as follows: $150 million on April 2010 and $50 million on April 2013, translated at the December 31, 2003 foreign exchange rate of 0.7713 Cdn/U.S. | |||
| (2) | Interest payments on U.S.-denominated debt, calculated based on the December 31, 2003 foreign exchange rate. | |||
| (3) | The annual remediation trust fund payment of $250,000 has been assumed for the next five years based on the current Judy Creek remediation trust fund agreement. The assets in the Judy Creek remediation trust fund and the outstanding asset retirement obligations are evaluated every five years. The contribution level beyond 2008 is not known. | |||
Risk Management
Pengrowth uses forward and futures contracts to manage its exposure to commodity price fluctuations. Commodity price hedges in place at December 31, 2003 are provided in Note 18 to the financial statements. Subsequent to year-end, Pengrowth has entered into additional contracts and now has the following volumes hedged for 2004:
| Crude Oil | Eastern Natural Gas | |||||||||||||||
| Volume | Average | Volume | Average | |||||||||||||
| (bbls/d) | Price* | (mcf/d) | Price* | |||||||||||||
| (Cdn $/bbl) | (Cdn $/mmbtu) | |||||||||||||||
| 2004 | 9,500 | $ | 38.11 | 13,830 | $ | 6.65 | ||||||||||
| * | before transportation |
In addition, subsequent to year-end, Pengrowth has entered into an agreement to purchase 5 megawatts of electricity from February 1, 2004 to December 31, 2004 at a price of $53.00 per megawatt hour. This constitutes approximately 20 percent of the electricity requirements of our operated properties for the period.
Pengrowth Energy Trust • 2003 annual report 59
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Trust Unit Information
| Volume | Value | |||||||||||||||||||||||
| Trust Unit Trading – TSX | High | Low | Close | (000s) | ($ millions) | |||||||||||||||||||
| 2003 | 1st quarter | $ | 15.90 | $ | 13.39 | $ | 14.25 | 20,122 | $ | 297.6 | ||||||||||||||
| 2nd quarter | 18.22 | 13.95 | 17.25 | 32,575 | 519.0 | |||||||||||||||||||
| 3rd quarter | 17.87 | 16.20 | 17.25 | 20,476 | 349.5 | |||||||||||||||||||
| 4th quarter | 22.22 | 16.75 | 21.25 | 24,220 | 451.6 | |||||||||||||||||||
| Year | $ | 22.22 | $ | 13.39 | $ | 21.25 | 97,393 | $ | 1,617.7 | |||||||||||||||
| 2002 | 1st quarter | $ | 16.23 | $ | 13.25 | $ | 16.13 | 11,395 | $ | 165.7 | ||||||||||||||
| 2nd quarter | 17.00 | 14.60 | 15.05 | 12,588 | 197.1 | |||||||||||||||||||
| 3rd quarter | 15.63 | 13.01 | 14.90 | 9,367 | 140.8 | |||||||||||||||||||
| 4th quarter | 14.99 | 13.42 | 14.73 | 17,760 | 250.1 | |||||||||||||||||||
| Year | $ | 17.00 | $ | 13.01 | $ | 14.73 | 51,110 | $ | 753.7 | |||||||||||||||
| Trust Unit Trading – NYSE | Volume | Value | ||||||||||||||||||||||
| (listed on April 10, 2002) (in $US) | High | Low | Close | (000s) | ($ millions) | |||||||||||||||||||
| 2003 | 1st quarter | $ | 10.67 | $ | 9.07 | $ | 9.71 | 8,168 | $ | 80.8 | ||||||||||||||
| 2nd quarter | 13.80 | 9.40 | 12.83 | 22,500 | 271.1 | |||||||||||||||||||
| 3rd quarter | 13.13 | 11.55 | 12.81 | 18,614 | 230.2 | |||||||||||||||||||
| 4th quarter | 17.00 | 12.50 | 16.40 | 24,721 | 340.8 | |||||||||||||||||||
| Year | $ | 17.00 | $ | 9.07 | $ | 16.40 | 74,003 | $ | 922.9 | |||||||||||||||
| 2002 | 2nd quarter | $ | 10.90 | $ | 9.50 | $ | 9.93 | 1,784 | $ | 18.1 | ||||||||||||||
| 3rd quarter | 10.25 | 8.40 | 9.37 | 1,141 | 11.0 | |||||||||||||||||||
| 4th quarter | 9.79 | 8.50 | 9.27 | 6,747 | 60.6 | |||||||||||||||||||
| Year | $ | 10.90 | $ | 8.40 | $ | 9.27 | 9,672 | $ | 89.7 | |||||||||||||||
Pengrowth had 123,873,651 trust units outstanding at December 31, 2003, compared to 110,562,327 trust units at December 31, 2002. The weighted average number of units during the year was 115,912,374 (2002 – 89,922,886).
In 2003, Pengrowth raised a total of $210.2 million net proceeds from new equity, issuing a total of 13.3 million additional trust units. On July 23, 2003 Pengrowth completed a public offering of 8.5 million units at $16.95 per unit to raise total gross proceeds of $144.1 million, and net proceeds of $136.3 million. During 2003, Pengrowth issued 1.5 million units under the DRIP plan at an average price of $15.31 per unit, raising additional equity of $22.2 million. A further 3.4 million units were issued under the employee trust unit option and rights plans, at an average price of $15.39 per trust unit, to raise an additional $51.7 million in new equity.
60 Pengrowth Energy Trust • 2003 annual report
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Summary of Quarterly Results
The following table is a summary of quarterly results for 2003 and 2002. As this table illustrates, net income and distributable cash were impacted positively by the acquisition of the British Columbia properties in the fourth quarter of 2002. As Pengrowth did not make any significant acquisitions in 2003, production declined to the fourth-quarter level of approximately 48,000 boe per day. Natural production declines were partially offset by Pengrowth’s 2003 development program on existing properties.
This table also shows the relatively high commodity prices sustained since the first quarter of 2002, which have had a positive impact on net income and distributable cash.
| 2003 | ||||||||||||||||||||
| ($ thousands) | Q1 | Q2 | Q3 | Q4 | Total | |||||||||||||||
| Oil and gas sales | $ | 202,801 | $ | 167,222 | $ | 160,695 | $ | 152,077 | $ | 682,795 | ||||||||||
| Net income | $ | 62,920 | $ | 54,214 | $ | 34,808 | $ | 37,355 | $ | 189,297 | ||||||||||
| Net income per unit | $ | 0.57 | $ | 0.49 | $ | 0.29 | $ | 0.31 | $ | 1.63 | ||||||||||
| Net income per unit – diluted | $ | 0.57 | $ | 0.48 | $ | 0.29 | $ | 0.30 | $ | 1.63 | ||||||||||
Distributable cash(1) | $ | 97,221 | $ | 71,774 | $ | 72,951 | $ | 71,469 | $ | 313,415 | ||||||||||
| Actual distributions paid or declared per unit | $ | 0.75 | $ | 0.67 | $ | 0.63 | $ | 0.63 | $ | 2.68 | ||||||||||
| Daily production (boe) | 50,827 | 48,839 | 48,850 | 47,653 | 49,033 | |||||||||||||||
| Average price per boe | $ | 44.33 | $ | 37.63 | $ | 35.76 | $ | 34.69 | $ | 38.15 | ||||||||||
| Operating netback per boe | $ | 26.48 | $ | 21.11 | $ | 20.54 | $ | 20.43 | $ | 22.17 | ||||||||||
| 2002 | ||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | Total | ||||||||||||||||
| Oil and gas sales | $ | 91,634 | $ | 111,544 | $ | 111,205 | $ | 167,918 | $ | 482,301 | ||||||||||
| Net income | $ | 1,904 | $ | 15,167 | $ | 14,011 | $ | 25,873 | $ | 56,955 | ||||||||||
| Net income per unit | $ | 0.02 | $ | 0.18 | $ | 0.16 | $ | 0.25 | $ | 0.63 | ||||||||||
| Net income per unit – diluted | $ | 0.02 | $ | 0.18 | $ | 0.15 | $ | 0.25 | $ | 0.63 | ||||||||||
Distributable cash(1) | $ | 33,118 | $ | 48,141 | $ | 46,139 | $ | 67,060 | $ | 194,458 | ||||||||||
| Actual distributions paid or declared per unit | $ | 0.41 | $ | 0.54 | $ | 0.52 | $ | 0.60 | $ | 2.07 | ||||||||||
| Daily production (boe) | 41,859 | 40,771 | 40,203 | 52,253 | 43,785 | |||||||||||||||
| Average price per boe | $ | 24.32 | $ | 30.06 | $ | 30.07 | $ | 34.93 | $ | 30.18 | ||||||||||
| Operating netback per boe | $ | 10.71 | $ | 15.34 | $ | 14.57 | $ | 17.50 | $ | 14.70 | ||||||||||
| (1) | See note 4 to the financial statements |
Pengrowth Energy Trust • 2003 annual report 61
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Selected Annual Information
| Financial Results | ||||||||||||
| ($ thousands) | 2003 | 2002 | 2001 | |||||||||
| Oil and gas sales | $ | 682,795 | $ | 482,301 | $ | 469,929 | ||||||
| Net income | $ | 189,297 | $ | 56,955 | $ | 88,185 | ||||||
| Net income per unit | $ | 1.63 | $ | 0.63 | $ | 1.24 | ||||||
Distributable cash(1) | $ | 313,415 | $ | 194,458 | $ | 215,787 | ||||||
| Actual distributions paid or declared per unit | $ | 2.68 | $ | 2.07 | $ | 3.01 | ||||||
| Total assets | $ | 1,673,718 | $ | 1,552,651 | $ | 1,270,208 | ||||||
Long term financial liabilities(2) | $ | 294,300 | $ | 316,501 | $ | 345,456 | ||||||
| Trust unitholders’ equity | $ | 1,159,433 | $ | 1,073,164 | $ | 828,540 | ||||||
| Units outstanding at year-end (thousands) | 123,874 | 110,562 | 82,240 | |||||||||
| (1) | See note 4 to the financial statements | |||
| (2) | Long-term debt plus Note Payable (excluding current portion) | |||
Impact on Net Income of Change in Accounting Policies
The implementation of new accounting policies in 2003 relating to stock-based compensation and asset retirement obligations has resulted in restatements of previously reported income. The restatements were required under the provisions of the new accounting standards.
The following table shows the impact of the new accounting policies on annual net income for the years presented:
| ($ thousands) | 2003 | 2002 | 2001 | |||||||||
| Net income before change in accounting policies | $ | 180,204 | $ | 49,067 | $ | 85,150 | ||||||
| Increase (decrease) in net income: | ||||||||||||
| Stock-based compensation | (189 | ) | – | – | ||||||||
| Asset retirement obligations | 9,282 | 7,888 | 3,035 | |||||||||
| Net income after change in accounting policies | $ | 189,297 | $ | 56,955 | $ | 88,185 | ||||||
The following table shows the impact of the new accounting policies on quarterly net income for periods which have been presented for comparative purposes:
| 2003 | ||||||||||||||||
| ($ thousands) | Q1 | Q2 | Q3 | Q4 | ||||||||||||
Net income before change in accounting policies(1) | $ | 61,050 | $ | 52,435 | $ | 33,025 | $ | 33,694 | ||||||||
| Increase (decrease) in net income: | ||||||||||||||||
Stock-based compensation(2) | (54 | ) | (12 | ) | (39 | ) | (84 | ) | ||||||||
Asset retirement obligations(3) | 1,924 | 1,791 | 1,822 | 3,745 | ||||||||||||
| Net income after change in accounting policies | $ | 62,920 | $ | 54,214 | $ | 34,808 | $ | 37,355 | ||||||||
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| 2002 | ||||||||||||||||
| ($ thousands) | Q1 | Q2 | Q3 | Q4 | ||||||||||||
Net income before change in accounting policies(1) | $ | 442 | $ | 13,604 | $ | 12,497 | $ | 22,524 | ||||||||
| Increase (decrease) in net income: | ||||||||||||||||
Stock-based compensation(2) | – | – | – | – | ||||||||||||
Asset retirement obligations(3) | 1,462 | 1,563 | 1,514 | 3,349 | ||||||||||||
| Net income after change in accounting policies | $ | 1,904 | $ | 15,167 | $ | 14,011 | $ | 25,873 | ||||||||
| (1) | This represents net income as reported before retroactive restatement for changes in accounting policies. | |||
| (2) | The new accounting policy for stock-based compensation was implemented in the fourth quarter of 2003. The first three quarters of 2003 have been restated as a result of this new policy. | |||
| (3) | The new accounting policy for asset retirement obligations was implemented in the fourth quarter of 2003. This new standard required retroactive application with restatement of all prior periods presented for comparative purposes. | |||
Business Risks
The amount of distributable cash available to unitholders and the value of Pengrowth Energy Trust units are subject to numerous risk factors. As the trust units allow investors to participate in the net cash flow from Pengrowth’s portfolio of producing oil and natural gas properties, the principal risk factors that are associated with the oil and gas business include, but are not limited to, the following influences:
| • | The prices of Pengrowth’s products (crude oil, natural gas and NGLs) fluctuate due to many factors including local and global market supply and demand, weather patterns, pipeline transportation and political stability. | |||
| • | The marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Operational or economic factors may result in the inability to deliver our products to market. | |||
| • | Geological and operational risks affect the quantity and quality of reserves and the costs of recovering those reserves. Our actual results will vary from our reserve estimates and those variations could be material. | |||
| • | Government royalties, income taxes, commodity taxes, and other taxes, levies and fees have a significant economic impact on Pengrowth’s financial results. Changes to federal and provincial legislation governing such royalties, taxes and fees could have a material impact on Pengrowth’s financial results and the value of Pengrowth trust units. | |||
| • | Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We may incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change. | |||
| • | Pengrowth’s oil and gas reserves will be depleted over time and our level of distributable cash and the value of our trust units could be reduced if reserves and production are not replaced. The ability to replace production depends on Pengrowth’s success in developing existing reserves, acquiring new reserves and financing this development and acquisition activity within the context of the capital markets. | |||
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| • | A significant portion of our properties are operated by third parties. If these operators fail to perform their duties properly or become insolvent, we may experience interruptions in production and revenues from these properties or incur additional liabilities and expenses as a result of the default of these third party operators. | |||
| • | Increased activity within the oil and gas sector can increase the cost of goods and services and make it more difficult to hire and retain professional staff. | |||
| • | Changing interest rates influence borrowing costs and the availability of capital. | |||
| • | Investors’ interest in the oil and gas sector may change over time which would affect the availability of capital and the value of Pengrowth trust units. | |||
| • | Inflation may result in escalating costs which could impact unitholder distributions and the value of Pengrowth trust units. | |||
| • | Canadian/ U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs as well as reserve acquisition costs. | |||
| • | The value of Pengrowth trust units is impacted directly by the related tax treatment of the trust units and the trust unit distributions and indirectly by the tax treatment of alternative equity investments. Changes in Canadian or U.S. tax legislation could adversely affect the value of our trust units. | |||
| • | In order to continue to qualify as a mutual fund trust. Pengrowth Trust cannot, and may not at any time, reasonably be considered to be established or maintained primarily for the benefit of non-resident persons. Canges in theIncome Tax Act(Canada), or changes in the level of foreign ownership may require Pengrowth to restrict or control the level of foreign ownership which could adversely affect the value of our trust units. | |||
Pengrowth mitigates some of these risks by:
| • | Fixing the price on a portion of its future crude oil and natural gas production. | |||
| • | Fixing the Canadian/ U.S. exchange rate through financial hedging contracts or by fixing commodity prices in Canadian dollars. | |||
| • | Offering competitive incentive-based compensation packages to attract and retain highly qualified and motivated professional staff. | |||
| • | Adhering to investment criteria for acquisitions. | |||
| • | Acquiring mature production with long-life reserves and proven production. | |||
| • | Performing extensive geological, geophysical, engineering and environmental analysis before committing to acquisitions and capital development projects. | |||
| • | Geographically diversifying its portfolio. | |||
| • | Controlling costs to maximize profitability. | |||
| • | Developing and adhering to policies and practices that protect the environment and meet or exceed the regulations imposed by the government. | |||
| • | Developing and adhering to safety policies and practices that meet or exceed regulatory standards. | |||
| • | Ensuring strong third-party operators for non-operated properties. | |||
| • | Carrying insurance to cover physical losses and business interruption. | |||
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Outlook
Our focus in 2004 continues to be on creating unitholder value. We successfully accomplished this mission in 2003 delivering distributions of $2.68 per unit and appreciation of trust units in the market place. In 2004 we will again optimize the distributions to our unitholders within the parameters of maintaining a prudent financial structure and allowing us to act on longer-term growth opportunities for our unitholders.
We will continue in 2004 to strive to accomplish many of the objectives which have successfully grown the business and unitholders’ value over the years including:
| • | Maintaining a balanced property portfolio which includes gas, oil and liquids as well as a mix of operated versus non-operated properties: | |||
| • | Growing production and reserves through potentially accretive acquisitions; | |||
| • | The continued optimization of our existing properties and either reducing declines or growing production through development drilling, workovers and field optimization strategies; | |||
| • | Maintaining a strong focus on operational and technical excellence to reduce developmental risks, maintain relatively low operating costs and maximize netbacks; | |||
| • | Actively managing financial risk including reducing the cost of capital for acquisitions and reinvestment, maximizing sales prices and managing our credit exposure; | |||
| • | Protecting the health and safety of our employees and the public, and preserving the quality of our environment; | |||
| • | Continuing to farm out our higher risk undeveloped acreage to exploration companies which allows Pengrowth participatation in the upside potential with much reduced capital risk to our unitholders; | |||
| • | Utilizing proven and cost-effective technologies; and | |||
| • | Maintaining our commitment to making a positive difference in the community at-large. | |||
| • | Seeking to reduce the volatility of returns through market risk management and the acquisition of steady cash flow producing assets such as infrastructure systems, gas plants, gas gathering systems, other infrastructure type assets related to the oil and gas industry. | |||
In 2004 we have planned the largest capital program of the Trust’s history at $135 million which we will strive to deploy in a manner which enhances value for our unitholders.
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APPENDIX C
CONSOLIDATED FINANCIAL STATEMENTS OF PENGROWTH ENERGY TRUST (INCLUDED ON PAGES
66 THROUGH 97 OF THE PENGROWTH ENERGY TRUST 2003 ANNUAL REPORT), INCLUDING
FOOTNOTE 20 THEREOF WHICH INCLUDES A RECONCILIATION OF THE CONSOLIDATED
FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
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Management’s Report
Management’s Responsibility to the Unitholders
The financial statements are the responsibility of the management of Pengrowth Energy Trust. They have been prepared in accordance with generally accepted accounting principles, using management’s best estimates and judgements, where appropriate.
Management is responsible for the reliability and integrity of the financial statements, the notes to the financial statements, and other financial information contained in this report. In the preparation of these statements, estimates are sometimes necessary because a precise determination of certain assets and liabilities is dependent on future events. Management believes such estimates have been based on careful judgements and have been properly reflected in the accompanying financial statements.
Management is also responsible for ensuring that it fulfills its responsibilities for financial reporting and internal control. The Board is assisted in exercising its responsibilities through the Audit Committee, which is composed of three independent non-management directors. The Committee meets periodically with management and the auditors to satisfy itself that management’s responsibilities are properly discharged, to review the financial statements and to recommend approval of the financial statements to the Board.
KPMG LLP, the independent auditors appointed by the unitholders, have audited Pengrowth Energy Trust’s consolidated financial statements in accordance with generally accepted auditing standards and provided an independent professional opinion. The auditors have full and unrestricted access to the Audit Committee to discuss their audit and their related findings as to the integrity of the financial reporting process.
| James S. Kinnear Chairman, President and Chief Executive Officer | Robert B. Hodgins Chief Financial Officer | |
| February 29, 2004 except for Note 11 which is as of March 4, 2004. | ||
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Auditors’ Report
To the Unitholders of Pengrowth Energy Trust
We have audited the consolidated balance sheets of Pengrowth Energy Trust as at December 31, 2003 and 2002 and the consolidated statements of income, trust unitholders’ equity and cash flow for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. 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 Trust as at December 31, 2003 and 2002 and the results of its operations and its cash flow for the years then ended in accordance with Canadian generally accepted accounting principles.
Chartered Accountants
Calgary, Canada
February 29, 2004 except for Note 11 which is as of March 4, 2004.
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Consolidated Balance Sheets
(Stated in thousands of dollars)
| As at December 31 | 2003 | 2002 | ||||||
| (restated see Note 3) | ||||||||
| ASSETS | ||||||||
| CURRENT ASSETS | ||||||||
| Cash and term deposits | $ | 64,154 | $ | 8,292 | ||||
| Accounts receivable | 65,570 | 41,426 | ||||||
| Inventory | 699 | 1,301 | ||||||
| Marketable Securities | – | 1,906 | ||||||
| 130,423 | 52,925 | |||||||
| REMEDIATION TRUST FUNDS (Note 5) | 7,392 | 6,679 | ||||||
| DEFERRED CHARGES (Note 12) | 5,544 | – | ||||||
| PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS (Note 7) | 1,530,359 | 1,493,047 | ||||||
| $ | 1,673,718 | $ | 1,552,651 | |||||
| LIABILITIES AND UNITHOLDERS’ EQUITY | ||||||||
| CURRENT LIABILITIES | ||||||||
| Accounts payable and accrued liabilities | $ | 54,196 | $ | 43,092 | ||||
| Distributions payable to unitholders | 52,139 | 45,315 | ||||||
| Due to Pengrowth Management Limited (Note 16) | 1,122 | 1,086 | ||||||
| Note payable (Note 9) | 10,000 | – | ||||||
| 117,457 | 89,493 | |||||||
| NOTE PAYABLE (Note 9) | 35,000 | – | ||||||
| LONG-TERM DEBT (Note 10) | 259,300 | 316,501 | ||||||
| ASSET RETIREMENT OBLIGATIONS (Note 8) | 102,528 | 73,493 | ||||||
| TRUST UNITHOLDERS’ EQUITY | 1,159,433 | 1,073,164 | ||||||
| COMMITMENTS (Note 19) | $ | 1,673,718 | $ | 1,552,651 | ||||
See accompanying notes to the consolidated financial statements.
Approved on behalf of Pengrowth Energy Trust
by Pengrowth Corporation, as Administrator:
| Director | Director |
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Consolidated Statements of Income
(Stated in thousands of dollars)
| Years ended December 31 | 2003 | 2002 | ||||||
| (restated see Note 3) | ||||||||
| REVENUES | ||||||||
| Oil and gas sales | $ | 682,795 | $ | 482,301 | ||||
| Processing and other income | 9,726 | 6,936 | ||||||
| Crown royalties, net of incentives | (108,325 | ) | (73,833 | ) | ||||
| Freehold royalties and mineral taxes | (6,580 | ) | (6,774 | ) | ||||
| 577,616 | 408,630 | |||||||
| Interest and other income | 840 | 274 | ||||||
| NET REVENUE | 578,456 | 408,904 | ||||||
| EXPENSES | ||||||||
| Operating | 149,032 | 129,802 | ||||||
| Amortization of injectants for miscible floods | 32,541 | 44,330 | ||||||
| Interest | 18,153 | 15,213 | ||||||
| Foreign exchange loss (gain) (Note 13) | (29,911 | ) | 182 | |||||
| General and administrative | 15,997 | 10,992 | ||||||
| Management and performance fee (Note 16) | 10,181 | 6,567 | ||||||
| Capital taxes | 1,798 | 483 | ||||||
| Depletion and depreciation | 185,270 | 140,775 | ||||||
| Accretion (Note 8) | 6,039 | 3,566 | ||||||
| 389,100 | 351,910 | |||||||
| INCOME BEFORE THE FOLLOWING | 189,356 | 56,994 | ||||||
| ROYALTY INCOME ATTRIBUTABLE TO ROYALTY UNITS OTHER THAN THOSE HELD BY PENGROWTH ENERGY TRUST | 59 | 39 | ||||||
| NET INCOME | $ | 189,297 | $ | 56,955 | ||||
| NET INCOME PER UNIT (Note 17) | ||||||||
| Basic | $ | 1.633 | $ | 0.633 | ||||
| Diluted | $ | 1.625 | $ | 0.633 | ||||
See accompanying notes to the consolidated financial statements.
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Consolidated Statements of Cash Flow
(Stated in thousands of dollars)
| Years ended December 31 | 2003 | 2002 | ||||||
| (restated see Note 3) | ||||||||
| CASH PROVIDED BY (USED FOR): | ||||||||
| OPERATING | ||||||||
| Net income | $ | 189,297 | $ | 56,955 | ||||
| Items not involving cash | ||||||||
| Depletion, depreciation and accretion | 191,309 | 144,341 | ||||||
| Amortization of injectants | 32,541 | 44,330 | ||||||
| Purchase of injectants | (23,037 | ) | (15,107 | ) | ||||
| Expenditures on remediation | (3,243 | ) | (1,607 | ) | ||||
| Unrealized foreign exchange gain (Note 13) | (30,940 | ) | – | |||||
| Trust unit based compensation (Note 11) | 189 | – | ||||||
| Amortization of deferred charges (Note 12) | 204 | – | ||||||
| Loss (gain) on sale of marketable securities | 94 | (176 | ) | |||||
| Funds generated from operating activities | 356,414 | 228,736 | ||||||
| Changes in non-cash operating working capital (Note 14) | (9,863 | ) | 120 | |||||
| Cash provided by operating activities | 346,551 | 228,856 | ||||||
| FINANCING | ||||||||
| Distributions | (306,591 | ) | (171,350 | ) | ||||
| Change in long-term debt | (26,261 | ) | (28,955 | ) | ||||
| Note payable (Note 9) | 41,393 | – | ||||||
| Proceeds from issue of trust units | 210,198 | 382,127 | ||||||
| (81,261 | ) | 181,822 | ||||||
| INVESTING | ||||||||
| Expenditures on property acquisitions | (122,964 | ) | (391,761 | ) | ||||
| Expenditures on property, plant and equipment | (85,718 | ) | (55,631 | ) | ||||
| Proceeds on property dispositions | 2,835 | 43,153 | ||||||
| Deferred charges | (2,141 | ) | – | |||||
| Change in Remediation Trust Funds | (713 | ) | (209 | ) | ||||
| Purchase of marketable securities | – | (2,780 | ) | |||||
| Proceeds from sale of marketable securities | 1,812 | 1,050 | ||||||
| Change in non-cash investing working capital (Note 14) | (2,539 | ) | (5 | ) | ||||
| (209,428 | ) | (406,183 | ) | |||||
| CHANGE IN CASH AND TERM DEPOSITS | 55,862 | 4,495 | ||||||
| CASH AND TERM DEPOSITS AT BEGINNING OF YEAR | 8,292 | 3,797 | ||||||
| CASH AND TERM DEPOSITS AT END OF YEAR | $ | 64,154 | $ | 8,292 | ||||
See accompanying notes to the consolidated financial statements.
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Consolidated Statements of
Trust Unitholders’ Equity
(Stated in thousands of dollars)
| Years ended December 31 | 2003 | 2002 | ||||||
| (restated see Note 3) | ||||||||
| Unitholders’ equity at beginning of (Note 3) | $ | 1,073,164 | $ | 828,540 | ||||
| Units issued, net of issue costs (Note 11) | 210,198 | 382,127 | ||||||
| Net income for year | 189,297 | 56,955 | ||||||
| Contributed Surplus (Note 11) | 189 | – | ||||||
| Distributable cash (Note 4) | (313,415 | ) | (194,458 | ) | ||||
| TRUST UNITHOLDERS’ EQUITY AT END OF YEAR | $ | 1,159,433 | $ | 1,073,164 | ||||
See accompanying notes to the consolidated financial statements.
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Notes to Consolidated Financial Statements
Years ended December 31, 2003 and 2002
(Tabular amounts are stated in thousands of dollars except per unit amounts.)
1. Structure of the Trust
Pengrowth Energy Trust (“EnergyTrust”) is a closed-end investment trust created under the laws of the Province of Alberta pursuant to a Trust Indenture dated December 2, 1988 (as amended) between Pengrowth Corporation (“Corporation”) and ComputerShare Investor Services Inc. (“Computershare”). Operations commenced on December 30, 1988. The beneficiaries of EnergyTrust are the holders of trust units (the “unitholders”).
EnergyTrust acquires and holds royalty units issued by the Corporation, which entitles EnergyTrust to the net revenue generated by Corporation’s petroleum and natural gas properties less certain defined charges. In addition, unitholders are entitled to receive the net cash flows from other investments that are held directly by EnergyTrust. EnergyTrust owns approximately 99.9 percent of the royalty units issued by the Corporation.
Pengrowth Management Limited (the “Manager”) is responsible for the management of the business affairs of the Corporation and the administration of EnergyTrust. The Manager owns 9 percent of the common shares of Corporation, and the Manager is controlled by an officer and a director of the Corporation. The remaining 91 percent of the common shares of the Corporation are owned by EnergyTrust.
Under the terms of the Royalty Indenture, the Corporation is entitled to retain a 1 percent share of royalty income and all miscellaneous income (the “Residual Interest”) to the extent this amount exceeds the aggregate of debt service charges, general and administrative expenses, and management fees. In 2003 and 2002, this Residual Interest, as computed, did not result in any income retained by Pengrowth Corporation.
2. Significant Accounting Policies
BASIS OF PRESENTATION
EnergyTrust’s consolidated financial statements have been prepared in accordance with generally accepted accounting principles in Canada and they include the accounts of EnergyTrust and the accounts of Corporation (collectively referred to as “Pengrowth”). All inter-entity transactions have been eliminated. These financial statements do not contain the accounts of the Manager.
EnergyTrust owns 91 percent of the shares of Corporation and, through the royalty, obtains substantially all the economic benefits of Corporation. In addition, the unitholders of EnergyTrust have the right to elect the majority of the board of directors of Corporation.
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JOINT INTEREST OPERATIONS
A significant proportion of Pengrowth’s petroleum and natural gas development and production activities are conducted with others and accordingly the accounts reflect only Pengrowth’s proportionate interest in such activities.
PROPERTY PLANT AND EQUIPMENT
Pengrowth follows the full cost method of accounting for oil and gas properties and facilities whereby all costs of acquiring such interests are capitalized and depleted on the unit of production method based on proved reserves before royalties as estimated by independent engineers. The fair value of the future estimated asset retirement obligations associated with properties and facilities are also capitalized and depleted on the unit-of-production method (see Asset Retirement Obligation). Natural gas production and reserves are converted to equivalent units of crude oil using their relative energy content.
General and administrative costs are not capitalized other than to the extent they are directly related to a successful acquisition, or to the extent of Pengrowth’s working interest in capital expenditure programs to which overhead fees can be recovered from partners. Overhead fees are not charged on 100 percent owned projects.
Proceeds from disposals of oil and gas properties and equipment are credited against capitalized costs unless the disposal would alter the rate of depletion and depreciation by more than 20 percent, in which case a gain or loss on disposal is recorded.
Pengrowth places a limit on the carrying value of property, plant and equipment and other assets, which may be depleted against revenues of future periods (the “ceiling test”). The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.
INJECTANT COSTS
Injectants (mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated as 30 months.
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INVENTORY
Inventories of crude oil, natural gas and natural gas liquids are stated at the lower of cost and net realizable value.
ASSET RETIREMENT OBLIGATIONS
Pengrowth recognizes the fair value of an Asset Retirement Obligation (“ARO”) in the period in which it is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit-of-production method based on proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO.
Pengrowth has placed cash in segregated remediation trust accounts to fund certain asset retirement obligations for the Judy Creek and Swan Hills properties, and the SOEP facilities. Contributions to these remediation trust accounts and expenditures on ARO not funded by the trust accounts are charged against distributable cash in the period incurred.
INCOME TAXES
EnergyTrust is a taxable trust under the Canadian Income Tax Act. As income taxes are the responsibility of the individual unitholders and EnergyTrust distributes all of its taxable income to its unitholders, no provision has been made for income taxes by EnergyTrust in these financial statements.
The Corporation follows the tax liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the Corporation’s financial statements and their respective tax bases, using enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.
TRUST UNIT COMPENSATION PLANS
Pengrowth has unit based compensation plans, which are described in Note 11. Compensation expense associated with unit based compensation plans is deferred and recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus. Compensation expense is based on the fair value of the unit based compensation at the date of grant using a modified Black-Scholes option pricing model.
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Any consideration received upon the exercise of the unit based compensation together with the amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in unitholders’ equity.
Pengrowth does not have any outstanding unit compensation plans that call for settlement in cash or other assets. Grants of such items, if any, will be recorded as expenses and liabilities based on the intrinsic value.
RISK MANAGEMENT
Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations, foreign currency and interest rate exposures. Pengrowth’s practice is not to utilize financial instruments for trading or speculative purposes.
Pengrowth formally documents relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. This process includes linking derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. Pengrowth also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items.
Pengrowth uses forward, futures and swap contracts to manage its exposure to commodity price fluctuations. The net receipts or payments arising from these contracts are recognized in income as a component of oil and gas sales during the same period as the corresponding hedged position.
Foreign exchange translation gains and losses on foreign currency exchange swaps used to hedge U.S. dollar denominated gas sales are recognized in income as a component of natural gas sales during the same period as the corresponding hedged position.
Interest rate swap agreements are used as part of Pengrowth’s program to manage the fixed and floating interest rate mix of Pengrowth’s total debt portfolio and related overall cost of borrowing. The interest rate swap agreements involve the periodic exchange of payments without the exchange of the notional principal amount upon which the payments are based, and are recorded as an adjustment of interest expense on the hedged debt instrument.
MEASUREMENT UNCERTAINTY
The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended.
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The amounts recorded for depletion, depreciation, amortization of injectants and the asset retirement obligations are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.
EARNINGS PER UNIT
In calculating diluted net income per unit, Pengrowth follows the treasury stock method to determine the dilutive effect of trust unit options and other dilutive instruments. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations.
CASH AND TERM DEPOSITS
Pengrowth considers term deposits with a maturity of three months or less to be cash equivalents.
REVENUE RECOGNITION
Revenue from the sale of oil and natural gas is recognized when the product is delivered. Revenue from processing and other miscellaneous sources is recognized upon completion of the relevant service.
COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform to the presentation adopted in the current year.
3. Change in Accounting Policies
FULL COST ACCOUNTING GUIDELINE
Effective January 1, 2003, Pengrowth adopted a new Canadian accounting standard relating to full cost accounting for oil and gas entities, as outlined in Note 2.
Prior to adopting the new standard, the limit on the aggregate carrying value of the property, plant and equipment and other assets that may be carried forward for depletion against future revenues was based on the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost or market of unproved reserves and the cost of major development projects less the estimated future costs for administration, financing, asset retirement obligations and income taxes.
There were no changes to net income, property plant and equipment and other assets or any other reported amounts in the financial statements as a result of adopting the standard.
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ASSET RETIREMENT OBLIGATIONS (ARO)
Effective January 1, 2002, Pengrowth retroactively adopted, with restatement of prior periods, a new accounting standard relating to asset retirement obligations, as outlined in Note 2. Prior to adopting the standard, Pengrowth recognized a provision for future site restoration costs over the life of the oil and gas properties and facilities using a unit of production method.
As a result of this change, net income for the year ended December 31, 2003 increased $9.3 million. The ARO increased by $41.0 million and property, plant and equipment and other assets, net of accumulated depletion increased by $69.5 million as at December 31, 2003. Opening 2003 unitholders’ equity increased by $19.2 million to reflect the cumulative impact of accretion and depletion expense, net of the cumulative site restoration provision.
The previously reported amounts for 2002 have been restated due to the retroactive application of this new standard. Net income for the year ended December 31, 2002 increased by $7.9 million. The ARO increased by $29.2 million and property, plant and equipment and other assets, net of accumulated depletion increased by $48.4 million as at December 31, 2002. Opening 2002 unitholders’ equity increased by $11.3 million to reflect the cumulative impact of accretion and depletion expense, less the previously recorded cumulative site restoration provision.
There was no impact on Pengrowth’s cash flow as a result of adopting the standard.
TRUST UNIT BASED COMPENSATION PLAN
Effective January 1, 2003, Pengrowth prospectively adopted amendments to a Canadian accounting standard relating to recognizing the compensation expense associated with unit based compensation plans, as outlined in Note 2. Under the amended standards, Pengrowth must recognize compensation expense based on the fair value of the trust unit options and rights granted under Pengrowth’s unit based compensation plans. Pengrowth uses a modified Black-Scholes option pricing model to determine the fair value of trust unit based compensation plans at the date of grant.
For trust unit options and rights granted in 2002, Pengrowth elected not to recognize compensation expense but provide pro forma disclosure as if the amended accounting standards were adopted retroactively.
As a result of adopting this amended standard, net income for the year ended December 31, 2003 decreased by $189,000 and contributed surplus increased by $189,000. Net income for 2002 remains unchanged with respect to trust unit options and rights granted in 2002 and the pro forma results are disclosed in Note 11.
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4. Distributable Cash
There is no standardized measure of Distributable Cash and therefore Distributable Cash, as presented below, may not be comparable to similar measures presented by other trusts.
| 2003 | 2002 | |||||||||
| Net income | $ | 189,297 | $ | 56,955 | ||||||
| Add (Deduct): | Depletion, depreciation and accretion | 191,309 | 144,341 | |||||||
| ARO expenses not covered by the trust | ||||||||||
| funds and trust fund contributions | (3,956 | ) | (1,816 | ) | ||||||
| Unrealized foreign exchange gain (Note 13) | (30,940 | ) | – | |||||||
| Non-cash compensation expense | 189 | – | ||||||||
| Distributable cash before withholding | 345,899 | 199,480 | ||||||||
| Cash withheld to fund capital expenditures | (32,484 | ) | (5,022 | ) | ||||||
| Distributable cash | 313,415 | 194,458 | ||||||||
| Less: Actual distributions paid or declared | (313,381 | ) | (193,395 | ) | ||||||
| Balance to be distributed | $ | 34 | $ | 1,063 | ||||||
| Actual distributions paid or declared per unit | $ | 2.680 | $ | 2.070 | ||||||
The per unit amount of distributions paid or declared reflect actual distributions paid or declared based on units outstanding at the time. Distributions are declared payable during the month following the month in which the distributions were earned. Distributions are paid to unitholders on the 15th day of the second month after the distributions are earned.
Pursuant to a Unitholder resolution on April 23, 2002, the Board of Directors of Pengrowth Corporation may elect to retain up to 20 percent of gross revenues to provide for the payment of future capital expenditures or for the payment of future distributions. Commencing with the January 15, 2003 distribution to unitholders, approximately 10 percent of funds available for distribution have been withheld. Subject to the limit of 20 percent of gross revenues approved by unitholders, the Board of Directors may elect to increase (or decrease) the amount withheld in the future.
5. Remediation Trust Funds
Pengrowth is required to make contributions to a remediation trust fund that is used to cover certain ARO of the Judy Creek properties. Pengrowth makes monthly contributions to the fund of $0.10 per boe of production from the Judy Creek properties and an annual lump sum contribution of $250,000.
Every five years Pengrowth must evaluate the assets in the trust fund and the outstanding asset retirement obligations, and make recommendations to the former owner of the Judy Creek properties as to whether contribution levels should be changed. Pengrowth is currently in discussions in respect of required contributions for 2004 and future periods. If an agreement is not reached regarding the changes in the contribution level, the matter may be arbitrated.
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Commencing in May 2003, Pengrowth was required, pursuant to various agreements with the Sable Offshore Energy Project (SOEP) partners, to make contributions to a remediation trust fund that will be used to fund ARO of the SOEP facilities and properties. Pengrowth has made monthly contributions to the fund of $0.02 per mcf of natural gas production and $0.08 per boe of natural gas liquids production from SOEP. An additional $0.02 per mcf of natural gas production will be required as a result of the acquisitions in December 2003 (see Note 6).
The following summarizes Pengrowth’s trust fund contributions for 2003 and 2002 and Pengrowth’s expenditures on ARO not covered by the trust funds:
| 2003 | 2002 | |||||||
| Contributions to Judy Creek Remediation Trust Fund | $ | 910 | $ | 893 | ||||
| Contributions to SOEP Environmental Restoration Fund | 181 | – | ||||||
| Expenditures related to Judy Creek Remediation Trust Fund | (378 | ) | (684 | ) | ||||
| 713 | 209 | |||||||
| Expenditures on ARO not covered by the trust funds | 2,865 | 923 | ||||||
| Expenditures on ARO covered by the trust funds | 378 | 684 | ||||||
| 3,243 | 1,607 | |||||||
| Total trust fund contributions and ARO expenditures not covered by the trust funds | $ | 3,956 | $ | 1,816 | ||||
6. Acquisitions
In May 2003, Pengrowth acquired an 8.4 percent working interest in the SOEP processing facilities, downstream of the Thebaud central processing platform, for approximately $57 million.
In June 2003, Pengrowth acquired interests in eleven significant discovery licenses from Nova Scotia Resources (Ventures) Limited (NSRVL) for $4.5 million plus a ten percent Net Profits Interest to NSRVL.
In December 2003, Pengrowth acquired an 8.4 percent working interest in the SOEP offshore production platforms and associated sub-sea field gathering lines from Emera Offshore Incorporated (Emera) for $65 million. The consideration for this acquisition included cash of $20 million and a $45 million note payable over three years (see Note 9).
In conjunction with the December acquisition, Pengrowth exchanged its royalty interest in SOEP for a direct working interest in SOEP.
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In October 2002, Pengrowth acquired substantially all of the crude oil and natural gas assets held by Calpine Canada Natural Gas Partnership (Calpine) in northern British Columbia for $377.4 million, net of adjustments, with the consideration consisting of cash and the tendering of debt securities of Calpine Corporation and its subsidiaries purchased by Pengrowth on the open market. Also in October 2002, Pengrowth sold to Progress Energy Ltd. for consideration of $25.4 million certain crude oil and natural gas assets acquired from Calpine. The acquisition was accounted for by the purchase method with the results of operations of the acquired assets included in the financial statements from the date of acquisition.
The following unaudited pro forma information provides an indication of what Pengrowth’s results of operations would have been had the Calpine acquisition taken place on January 1, 2002.
| 2002 | ||||
| (unaudited) | ||||
| Oil and gas sales | $ | 603,683 | ||
| Net income | $ | 90,661 | ||
| Net income per unit: | ||||
| Basic | $ | 0.847 | ||
| Diluted | $ | 0.847 | ||
7. Property, Plant and Equipment and Other Assets
| 2003 | 2002 | |||||||
| PROPERTY, PLANT AND EQUIPMENT | ||||||||
| Property, Plant and Equipment, at cost | $ | 2,281,166 | $ | 2,049,080 | ||||
| Accumulated depletion and depreciation | (775,103 | ) | (589,833 | ) | ||||
| Net book value of property, plant and equipment | 1,506,063 | 1,459,247 | ||||||
| OTHER ASSETS | ||||||||
| Deferred injectant costs | 24,296 | 33,800 | ||||||
| Net book value of property, plant and equipment and other assets | $ | 1,530,359 | $ | 1,493,047 | ||||
Property, plant and equipment includes $69.5 million (2002 – $48.4 million), net of accumulated depletion, related to the ARO.
Pengrowth performed a ceiling test calculation at December 31, 2003 to assess the recoverable value of the property, plant and equipment and other assets. The oil and gas future prices are based on the January 1, 2004 commodity price forecast of our independent reserve evaluators.
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These prices have been adjusted for commodity price differentials specific to Pengrowth. The following table summarizes the benchmark prices used in the ceiling test calculation. Based on these assumptions, the undiscounted value of future net revenues from Pengrowth’s proved reserves exceeded the carrying value of property, plant and equipment and other assets at December 31, 2003.
| Foreign | Edmonton Light | |||||||||||||||
| WTI Oil | Exchange | Crude Oil | AECO Gas | |||||||||||||
| Year | ($U.S./bbl) | Rate | ($Cdn/bbl) | ($Cdn/mmbtu) | ||||||||||||
| 2004 | 29.00 | 0.75 | 37.75 | 5.85 | ||||||||||||
| 2005 | 26.00 | 0.75 | 33.75 | 5.15 | ||||||||||||
| 2006 | 25.00 | 0.75 | 32.50 | 5.00 | ||||||||||||
| 2007 | 25.00 | 0.75 | 32.50 | 5.00 | ||||||||||||
| 2008 | 25.00 | 0.75 | 32.50 | 5.00 | ||||||||||||
| 2009 - 2014 | 25.00 | 0.75 | 32.50 | 5.00 | ||||||||||||
| �� | ||||||||||||||||
| Escalate thereafter | 1.5% per year | 1.5% per year | 1.5% per year | |||||||||||||
8. Asset Retirement Obligations
The total future asset retirement obligations were estimated by management based on Pengrowth’s working interest in its wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. Pengrowth has estimated the net present value of its total asset retirement obligations to be $103 million as at December 31, 2003, based on a total future liability of $352 million. These costs are expected to be made over 51 years with the majority of the costs incurred between 2014 and 2040. Pengrowth’s credit adjusted risk free rate of eight percent and an inflation rate of 1.5 percent were used to calculate the net present value of the asset retirement obligations.
The following reconciles Pengrowth’s asset retirement obligations:
| 2003 | 2002 | |||||||
| ARO, beginning of year | $ | 73,493 | $ | 42,123 | ||||
| Increase in liabilities during the year related to: | ||||||||
| Additions | 11,086 | 29,411 | ||||||
| Revisions | 15,153 | – | ||||||
| Accretion expense | 6,039 | 3,566 | ||||||
| Liabilities settled during the year | (3,243 | ) | (1,607 | ) | ||||
| ARO, end of year | $ | 102,528 | $ | 73,493 | ||||
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9. Note Payable
The note payable is due to Emera in respect of the acquisition of the SOEP facility (Note 6). The note payable is secured by Pengrowth’s woring interest in SOEP. The note payable is non-interest bearing with payments due as follows: $10 million on December 30, 2004, $15 million on December 29, 2005, and $20 million on December 31, 2006.
At December 31, 2003, $3.6 million has been recorded as a deferred charge representing the imputed interest on the non-interest bearing note. This amount will be recognized as interest expense over the period outstanding for each individual instalment.
10. Long-Term Debt
| As at December 31, | 2003 | 2002 | ||||||
| U.S. dollar denominated debt: | ||||||||
| $150 million senior unsecured notes at | ||||||||
| 4.93 percent due April 2010 | $ | 217,680 | $ | – | ||||
| $50 million senior unsecured notes at | ||||||||
| 5.47 percent due April 2013 | 72,560 | – | ||||||
| Unrealized foreign exchange gain on translation | (30,940 | ) | – | |||||
| 259,300 | – | |||||||
| Canadian dollar revolving credit borrowings | – | 316,501 | ||||||
| $ | 259,300 | $ | 316,501 | |||||
On April 23, 2003, Pengrowth closed a U.S.$200 million private placement of senior unsecured notes to a group of U.S. investors. The notes were offered in two tranches of U.S.$150 million at 4.93 percent due April 2010 and U.S.$50 million at 5.47 percent due in April 2013. The notes contain certain financial maintenance covenants and interest is paid semi-annually. The proceeds from the private placement were used to repay a portion of Pengrowth’s outstanding bank debt. Costs incurred in connection with issuing the notes, in the amount of $2,141,000, are being amortized straight line over the term of the notes (see Note 12).
The Corporation has a $200 million revolving credit facility syndicated among eight financial institutions with an extendible 364 day revolving period and a two year amortization term period. In addition, it has a $35 million demand operating line of credit. At December 31, 2003, the borrowing capacity under these facilities was reduced by outstanding letters of credit in the amount of approximately $47 million. In January 2004, this amount of outstanding letters of credit was reduced by $25 million. Interest payable on amounts drawn is at the prevailing bankers’ acceptance rates plus stamping fees, lenders’ prime lending rates, or U.S. libor rates plus applicable margins, depending on the form of borrowing by the Corporation. The margins and stamping fees vary from 0.25 percent to 1.50 percent depending on financial statement ratios and the form of borrowing.
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The credit facility will revolve until June 18, 2004, whereupon it may be renewed for a further 364 days, subject to satisfactory review by the lenders, or converted into a term facility with amounts outstanding under the facility repayable in eight equal quarterly instalments. The Corporation can post, at its option, security suitable to the banks in lieu of the first year’s payments.
11. Trust Units
The authorized capital of Pengrowth is 500,000,000 trust units.
| 2003 | 2002 | |||||||||||||||
| Number | Number | |||||||||||||||
| Trust Units Issued | of units | Amount | of units | Amount | ||||||||||||
| Balance, beginning of year | 110,562,327 | $ | 1,662,726 | 82,240,069 | $ | 1,280,599 | ||||||||||
| Issued for cash | 8,500,000 | 144,075 | 28,125,000 | 404,350 | ||||||||||||
| Less: issue expenses | – | (7,820 | ) | – | (24,989 | ) | ||||||||||
| Issued for cash on exercise of trust unit options and rights incentive options | 3,358,442 | 51,701 | 66,093 | 871 | ||||||||||||
| Issued for cash under Distribution Reinvestment Plan (“DRIP”) | 1,452,882 | 22,242 | 131,165 | 1,895 | ||||||||||||
| Balance, end of year | 123,873,651 | $ | 1,872,924 | 110,562,327 | $ | 1,662,726 | ||||||||||
Pursuant to the terms of the Royalty Indenture and the Trust Indenture, there is attached to each royalty unit granted by the Corporation the right to exchange such royalty unit for an equivalent number of trust units. ComputerShare, as Trustee has reserved 18,940 trust units for such future conversion.
DISTRIBUTION REINVESTMENT PLAN
The Distribution Reinvestment Plan (DRIP) entitles Canadian unitholders to reinvest cash distributions in additional units of EnergyTrust. The DRIP was amended effective January 2003 such that trust units under the amended plan are normally issued from treasury at a 5 percent discount to the weighted average closing price of all EnergyTrust units traded on the Toronto Stock Exchange and the New York Stock Exchange for the 20 trading days preceding a distribution payment date.
Prior to January 2003, the trust units under the plan were acquired in the open market at prevailing market prices or issued from treasury at the weighted average price of all EnergyTrust units traded on the Toronto Stock Exchange for the 20 trading days preceding a distribution payment date.
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TRUST UNIT OPTION PLAN
Pengrowth has a trust unit option plan under which directors, officers, employees and special consultants of the Corporation and the Manager are eligible to receive options. Under the terms of the plan, up to 10 percent of the issued and outstanding trust units to a maximum of 10 million units may be reserved for option and right grants. The options expire seven years from the date of grant. One third of the options vest on the grant date, one third on the first anniversary of the date of grant, and the remaining third on the second anniversary. As at December 31, 2003, options to purchase 2,014,903 trust units were outstanding (2002 – 4,451,131) that expire at various dates to June 28, 2009.
| 2003 | 2002 | |||||||||||||||
| Weighted | Weighted | |||||||||||||||
| Number | Average | Number | Average | |||||||||||||
| Trust Unit Options | of options | Exercise price | of options | Exercise price | ||||||||||||
| Outstanding at beginning of year | 4,451,131 | $ | 16.78 | 3,106,635 | $ | 17.78 | ||||||||||
| Granted | – | – | 1,895,603 | 15.14 | ||||||||||||
| Exercised | (2,374,182 | ) | 16.19 | (66,093 | ) | 13.17 | ||||||||||
| Cancelled | (62,046 | ) | 17.17 | (485,014 | ) | 17.23 | ||||||||||
| Outstanding at year-end | 2,014,903 | $ | 17.47 | 4,451,131 | $ | 16.78 | ||||||||||
| Exercisable at year-end | 1,999,436 | $ | 17.48 | 3,715,271 | $ | 17.04 | ||||||||||
The following table summarizes information about trust unit options outstanding and exercisable at December 31, 2003:
| Options Outstanding | Options Exercisable | |||||||||||||||||||
| Weighted- | ||||||||||||||||||||
| Number | Average | Weighted- | Number | Weighted- | ||||||||||||||||
| Outstanding | Remaining | Average | Exercisable | Average | ||||||||||||||||
| Range of Exercise Prices | At 12/31/03 | Contractual Life | Exercise Price | At 12/31/03 | Exercise Price | |||||||||||||||
| $12.00 to $14.99 | 260,893 | 4.7 years | $ | 13.19 | 245,426 | $ | 13.08 | |||||||||||||
| $15.00 to $16.99 | 235,090 | 3.7 | 15.09 | 235,090 | 15.09 | |||||||||||||||
| $17.00 to $17.99 | 756,545 | 2.6 | 17.49 | 756,545 | 17.49 | |||||||||||||||
| $18.00 to $20.50 | 762,375 | 2.6 | 19.64 | 762,375 | 19.64 | |||||||||||||||
| $12.00 to $20.50 | 2,014,903 | 3.0 | $ | 17.47 | 1,999,436 | $ | 17.48 | |||||||||||||
EMPLOYEE TRUST UNIT RIGHTS INCENTIVE PLAN
Pengrowth has an Employee Trust Unit Rights Incentive Plan (“Rights Incentive Plan”), pursuant to which rights to acquire Pengrowth trust units may be granted to the directors, officers, employees, and special consultants of the Corporation and the Manager. Under the Rights Incentive Plan, distributions per trust unit to trust unitholders in a calendar quarter which represent a return of more than 2.5 percent of the net property, plant and equipment at the end of such calendar quarter result in a reduction in the exercise price. Total price reductions calculated for 2003 were $1.47 per trust unit right (2002 – $0.64 per trust unit right). One third of the rights granted under the Rights Incentive Plan vest on the grant date, one third on the
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first anniversary date of the grant and the remaining on the second anniversary. The rights have an expiry date of five years from the date of grant. As at December 31, 2003, rights to purchase 1,112,140 trust units were outstanding (2002 – 1,964,100) that expire at various dates to October 30, 2008.
| 2003 | 2002 | |||||||||||||||
| Weighted | Weighted | |||||||||||||||
| Number | Average | Number | Average | |||||||||||||
| Rights Incentive Options | of Rights | Exercise Price | of Rights | Exercise Price | ||||||||||||
| Outstanding at beginning of year | 1,964,100 | $ | 13.29 | – | $ | – | ||||||||||
Granted(1) | 165,000 | 16.35 | 1,964,100 | 13.61 | ||||||||||||
| Exercised | (984,260 | ) | 13.49 | – | – | |||||||||||
| Cancelled | (32,700 | ) | 12.75 | – | – | |||||||||||
| Outstanding at year-end | 1,112,140 | $ | 12.20 | 1,964,100 | $ | 13.29 | ||||||||||
| Exercisable at year-end | 359,740 | $ | 11.92 | 654,700 | $ | 13.29 | ||||||||||
| (1) | Weighted average exercise price of rights granted are based on the exercise price at the date of grant. |
The following table summarizes information about rights incentive options outstanding and exercisable at December 31, 2003:
| Rights Outstanding | Rights Exercisable | |||||||||||||||||||
| Weighted- | ||||||||||||||||||||
| Number | Average | Weighted- | Number | Weighted- | ||||||||||||||||
| Outstanding | Remaining | Average | Exercisable | Average | ||||||||||||||||
| Range of Exercise Prices | At 12/31/03 | Contractual Life | Exercise Price | At 12/31/03 | Exercise Price | |||||||||||||||
| $11.00 to $12.99 | 991,940 | 3.8 years | $ | 11.80 | 346,740 | $ | 11.76 | |||||||||||||
| $13.00 to $14.99 | 42,300 | 4.2 | 14.03 | 2,500 | 14.03 | |||||||||||||||
| $15.00 to $16.99 | 77,900 | 4.7 | 16.32 | 10,500 | 16.80 | |||||||||||||||
| $11.00 to $16.99 | 1,112,140 | 3.9 | $ | 12.20 | 359,740 | $ | 11.92 | |||||||||||||
FAIR VALUE OF UNIT BASED COMPENSATION
Pengrowth recorded compensation expense and contributed surplus of $189,000 on rights incentive options granted in 2003. The amount of compensation expense was reduced for rights granted on or after January 1, 2003 which were subsequently cancelled prior to vesting.
For trust unit options and rights granted in 2002, Pengrowth has elected to disclose the pro forma effect as if the amended accounting standard had been adopted retroactively. For the year ended December 31, 2003, Pengrowth’s net income would have decreased by $1.6 million for the estimated compensation expense related to the trust unit options and rights granted on or after January 1, 2002.
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The following is the pro forma effect of retroactive adoption of the amended accounting standard on trust unit options and rights granted in 2002:
| 2003 | 2002 | |||||||
| Net income, as reported | $ | 189,297 | $ | 56,955 | ||||
| Compensation expense related to trust unit options granted in 2002 | (367 | ) | (899 | ) | ||||
| Compensation expense related to rights incentive options granted in 2002 | (1,279 | ) | (1,561 | ) | ||||
| Pro forma net income | $ | 187,651 | $ | 54,495 | ||||
| Pro forma net income per unit: | ||||||||
| Basic | $ | 1.619 | $ | 0.606 | ||||
| Diluted | $ | 1.611 | $ | 0.606 | ||||
The weighted average fair market value of trust unit options granted in 2002 was $0.73 per option using the Black-Scholes option pricing model with the following weighted average assumptions: risk-free interest rate of 4.4 percent, dividend yield of 13 percent, expected volatility of 27 percent, and expected life of five years.
The fair value of rights incentive options granted in 2003 and 2002 was estimated as 15 percent of the exercise price at the date of grant using a modified Black-Scholes option pricing model with the following assumptions: risk-free rate of 3.9 percent, volatility of 22 percent, expected life of five years and adjustments for the estimated distributions and reductions in the exercise price over the life of the right incentive option.
SHARE APPRECIATION RIGHTS
On October 15, 2002, all of the 426,000 Share Appreciation Rights (SAR’s) held by an officer of Pengrowth were converted into an equal number of options under the Trust Unit Option Plan. These options have a weighted average exercise price of $18.39, are fully vested and have expiry dates ranging from October 15 to December 1, 2004.
The SAR’s granted the right to receive a Payment Amount equal to any increase in the market price of the 426,000 trust units above the exercise price. Pengrowth, at its option, could have satisfied this Payment Amount with either a cash payment or the issue of trust units from treasury based on market prices at the time of exercise. The new standard for stock based compensation required the recognition of compensation expense equal to the amount of the excess of the market price above the exercise price for SAR’s. No compensation cost was recognized for the year ended December 31, 2002.
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TRUST UNIT SAVINGS PLAN
Pengrowth has a trust unit savings plan whereby qualifying employees may contribute from one to ten percent of their basic annual salary. Employee contributions are invested in trust units purchased on the open market. Pengrowth matches the employees’ contribution, investing in additional trust units purchased on the open market. Pengrowth’s share of contributions is recorded as compensation expense and amounted to $1,037,063 in 2003 (2002 – $844,213).
TRUST UNIT MARGIN PURCHASE PLAN
Pengrowth has a plan whereby the employees, officers and directors, and certain consultants of Corporation and the Manager can purchase trust units and finance up to 75 percent of the purchase price through an investment dealer, subject to certain participation limits and restrictions. Participants maintain personal margin accounts with the investment dealer and are responsible for all interest costs and obligations with respect to their margin loans.
The Corporation has provided a $5 million letter of credit to the investment dealer to guarantee amounts owing with respect to the plan. The amount of the letter of credit may fluctuate depending on the amounts financed pursuant to the plan. At December 31, 2003, 2,471,120 trust units were deposited under the plan (2002 – 2,529,698) with a market value of $52.5 million (2002 – $37.3 million) and a corresponding margin loan of $4.8 million (2002 – $11.3 million).
The investment dealer has limited the total margin loan available under the plan to the lesser of $15 million or 35 percent of the market value of the units held under the plan. If the market value of the trust units under the plan declines, the Corporation may be required to make payments or post additional letters of credit to the investment dealer. Any payments to be made by the Corporation would be reduced by proceeds of liquidating the individual’s trust units held under the plan. The maximum amount of the guarantee at December 31, 2003 was $4.8 million, the fair value of which is estimated to be a nominal amount.
REDEMPTION RIGHTS
Trust units are redeemable at the request of a Unitholder. The redemption right permits Unitholders in the aggregate to redeem a maximum of $25,000 of trust units in a month.
2004 OFFERING OF TRUST UNITS
On March 4, 2004 Pengrowth entered into an agreement to sell 8.2 million trust units at $18.40 per trust unit to raise gross proceeds of $150.9 million on a bought-deal basis. Pengrowth has granted the underwriters an option to purchase up to an additional 2.7 million trust units at the same offering price.
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12. Deferred Charges
| 2003 | 2002 | |||||||
| Imputed interest on note payable (Note 9) | $ | 3,607 | $ | – | ||||
| U.S. debt issue costs (net of accumulated amortization of $204) (Note 10) | 1,937 | – | ||||||
| $ | 5,544 | $ | – | |||||
13. Foreign Exchange Loss (Gain)
| 2003 | 2002 | |||||||
| Unrealized foreign exchange gain on translation of U.S. dollar denominated debt | $ | (30,940 | ) | $ | – | |||
| Realized foreign exchange losses | 1,029 | 182 | ||||||
| $ | (29,911 | ) | $ | 182 | ||||
The U.S. dollar denominated debt is translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Foreign exchange gains and losses are included income.
14. Other Cash Flow Disclosures
CHANGE IN NON-CASH OPERATING WORKING CAPITAL
| 2003 | 2002 | |||||||
| Accounts receivable | $ | (24,144 | ) | $ | (13,567 | ) | ||
| Inventory | 602 | 1,386 | ||||||
| Accounts payable and accrued liabilities | 13,643 | 11,738 | ||||||
| Due to Pengrowth Management Limited | 36 | 563 | ||||||
| $ | (9,863 | ) | $ | 120 | ||||
CHANGE IN NON-CASH INVESTING WORKING CAPITAL
| 2003 | 2002 | |||||||
| Accounts payable for capital accruals | $ | (2,539 | ) | $ | (5 | ) | ||
CASH PAYMENTS
| 2003 | 2002 | |||||||
| Cash payments made for taxes | $ | 1,834 | $ | 1,840 | ||||
| Cash payments made for interest | $ | 16,657 | $ | 15,400 | ||||
15. Income Taxes
In 2003, the cost basis for income tax purposes of property, plant and equipment exceeded the net book value by approximately $164 million (2002 – $149 million). A future tax asset of $56 million (2002 – $66 million) has been reduced to nil through a valuation allowance of $56 million (2002 – $66 million).
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16. Related Party Transactions
Pengrowth Management Limited provides certain services pursuant to a management agreement for which Pengrowth was charged $695,000 (2002 – $2,474,110) for acquisition fees, $520,000 (2002 – nil) for performance fees and $9,660,749 (2002 – $6,567,055) for a management fee. The law firm controlled by the corporate secretary charged $675,692 (2002 – $698,748) for legal and advisory services provided to Pengrowth by the corporate secretary. The transactions have been recorded at the exchange amount.
17. Amounts per Unit
The per unit amounts for net income are based on weighted average units outstanding for the year. The weighted average units outstanding for 2003 were 115,912,374 units (2002 – 89,922,886 units). In computing diluted net income per unit, 567,335 units were added to the weighted average number of units outstanding during the year ended December 31, 2003 (2002 – 69,398) for the dilutive effect of trust unit options and rights.
18. Financial Instruments
INTEREST RATE RISK
On April 23, 2003, Pengrowth completed a U.S. $200 million private placement of fixed rate seven and ten year term notes. Proceeds from the notes were used to pay down existing floating rate bank debt. The interest and principal payments on the term notes are payable in U.S. dollars. Pengrowth had previously fixed the interest rates on $125 million of Canadian bank debt using interest rate swaps. In 2003, Pengrowth terminated these interest rate swaps at a total cost including accrued interest of approximately $2,229,000.
FOREIGN CURRENCY EXCHANGE RISK
Pengrowth is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices. Pengrowth has mitigated some of this exchange risk by entering into fixed Canadian dollar crude oil and natural gas price swaps as outlined in the forward and futures contracts section below.
Pengrowth entered into a foreign exchange swap which fixed the Canadian to U.S. dollar exchange rate at Cdn$1.55 per U.S.$1 on U.S.$750,000 per month effective 2003 and 2004. This swap has mitigated a portion of the exchange risk on U.S. dollar denominated gas sales. The estimated fair value of the foreign exchange swap has been determined based on the amount Pengrowth would receive or pay to terminate the contract at year end. At December 31, 2003, the amount Pengrowth would receive to terminate the foreign exchange swap would be Cdn$2,169,000.
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CREDIT RISK
Pengrowth sells a significant portion of its oil and gas to commodity marketers, and the accounts receivable are subject to normal industry credit risks. The use of financial swap agreements involves a degree of credit risk that Pengrowth manages through its credit policies which are designed to limit eligible counterparties to those with “A” credit ratings or better.
FORWARD AND FUTURES CONTRACTS
Pengrowth has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. Pengrowth sells forward a portion of its future production through a combination of fixed price sales contracts with customers and commodity swap agreements with financial counterparties.
As at December 31, 2003, Pengrowth had fixed the price applicable to future production as follows:
Crude Oil:
| Volume | Reference | Price | ||||||||||
| Remaining Term | (bbl/d) | Point | Per bbl | |||||||||
| 2004 | ||||||||||||
| Financial: | ||||||||||||
| Jan 1, 2004 – Dec 31, 2004 | 9,500 | WTI (1) | $38.11 Cdn | |||||||||
Natural Gas:
| Volume | Reference | Price | ||||||||||
| Remaining Term | (mmbtu/d) | Point | Per mmbtu | |||||||||
| 2004 | ||||||||||||
| Financial: | ||||||||||||
| Jan 1, 2004 – Dec 31, 2004 | 5,000 | Tetco M3 (1) | $6.90 Cdn | |||||||||
| Jan 1, 2004 – Dec 31, 2004 | 7,000 | Transco Z6 | $3.90 U.S. | |||||||||
| (1) | Associated CDN$ / U.S.$ foreign exchange rate has been fixed. |
The estimated fair value of the financial crude oil and natural gas contracts has been determined based on the amounts Pengrowth would receive or pay to terminate the contracts at year-end. At December 31, 2003, the amounts Pengrowth would pay to terminate the financial crude oil and natural gas contracts would be $4,401,000 and $9,768,000, respectively.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of financial instruments included in the balance sheet, other than long term debt, the note payable and remediation trust funds, approximate their fair value due to their short maturity. The fair value of the remediation trust funds at December 31, 2003, was $7,479,000 (2002 – $6,729,000). The fair value of the U.S. denominated debt approximates its
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carrying value at December 31, 2003, as the rate on the debt did not vary significantly from market rates. The fair value of the note payable approximates its carrying value net of the imputed interest included in deferred charges.
19. Commitments
Pengrowth has future commitments under various agreements for oil and natural gas pipeline transportation, the purchase of carbon dioxide and operating leases. The commitment to purchase carbon dioxide arises as a result of Pengrowth’s working interest in the Weyburn CO2 miscible flood project (1).
| 2004 | 2005 | 2006 | 2007 | 2008 Thereafter | Total | |||||||||||||||||||||||
| Pipeline transportation | $ | 24,041 | $ | 23,642 | $ | 23,192 | $ | 19,448 | $ | 19,052 | $ | 19,439 | $ | 128,814 | ||||||||||||||
| Capital expenditures | 46,242 | 18,656 | 17,405 | – | – | – | 82,303 | |||||||||||||||||||||
| CO2 purchases | 5,372 | 6,534 | 5,725 | 4,830 | 4,651 | 30,396 | 57,508 | |||||||||||||||||||||
| Other commitments | 1,216 | 1,174 | 732 | 358 | 165 | – | 3,645 | |||||||||||||||||||||
| $ | 76,871 | $ | 50,006 | $ | 47,054 | $ | 24,636 | $ | 23,868 | $ | 49,835 | $ | 272,270 | |||||||||||||||
| (1) | Contract prices for CO2 are denominated in U.S. dollars and have been translated at the year end foreign exchange rate. |
| 20. | Reconciliation of Financial Statements to United States Generally Accepted Accounting Principles |
The significant differences between Canadian generally accepted accounting principles (“Canadian GAAP”) which, in most respects, conforms to generally accepted accounting principles in the United States (“U.S. GAAP”), as they apply to Pengrowth, are as follows:
| (a) | As required annually under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at 10 percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. Prior to 2003, under Canadian GAAP, the “ceiling test” was calculated without application of a discount factor. At December 31, 1998 and 1997 the application of the full cost ceiling test under U.S. GAAP resulted in a write-down of capitalized costs of $328.6 million and $49.8 million, respectively. At December 31, 2003 and 2002, the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs. |
| Where the amount of a ceiling test writedown under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion, depreciation, and amortization will differ in subsequent years. |
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| (b) | Under U.S. GAAP, interest and other income would not be included as a component of Net Revenue. |
| (c) | Effective January 1, 2003, Pengrowth prospectively adopted U.S. standards relating to recognizing the compensation expense associated with unit based compensation plans. Under U.S. GAAP Pengrowth adopted the following: |
| (i) | For trust unit options granted on or after January 1, 2003, the estimated fair value of the options is recognized as an expense over the vesting period. The compensation expense associated with trust unit options granted prior to January 1, 2003 is disclosed on a pro forma basis; | ||
| (ii) | For rights incentive options granted on or after January 1, 2003, the estimated fair value of the rights, determined using a modified Black-Scholes option pricing model, is recognized as an expense over the vesting period. The compensation expense associated with the rights granted prior to January 1, 2003 is disclosed on a pro forma basis. |
| The following is the pro forma effect of trust unit options and rights granted prior to January 1, 2003, had the fair value method of accounting been used: |
| Years ended December 31, | 2003 | 2002 | ||||||
| Net income – U.S. GAAP, as reported | $ | 236,181 | $ | 73,246 | ||||
| Compensation expense related to trust unit options granted prior to January 1, 2003 | (426 | ) | (890 | ) | ||||
| Compensation expense related to rights incentive options granted prior to January 1, 2003 | (1,279 | ) | (337 | ) | ||||
| Pro forma net income – U.S. GAAP | $ | 234,476 | $ | 72,019 | ||||
| Pro forma net income – U.S. GAAP per unit: | ||||||||
| Basic | $ | 2.02 | $ | 0.80 | ||||
| Diluted | $ | 2.01 | $ | 0.80 | ||||
| (d) | Marketable securities held by Pengrowth are classified as available-for-sale in accordance with the definitions of Statement of Financial Accounting Standards (“SFAS”) 115. Under provisions of this Statement, available-for-sale securities are reported at fair value, with unrealized holding gains and losses included in comprehensive income and reported as a separate component of unitholders’ equity until realized. |
| (e) | SFAS 130 requires the reporting of comprehensive income in addition to net income. Comprehensive income includes net income plus other comprehensive income; specifically, all changes in equity of a company during a period arising from non-owner sources. |
| (f) | Effective January 1, 2002, Pengrowth retroactively adopted with restatement of prior periods, a new Canadian accounting standard relating to asset retirement obligations, as outlined in Note 2. Canadian standards are consistent with the requirements under SFAS 143, “Accounting for Asset Retirement Obligations”, except under U.S. GAAP the change |
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| was effective January 1, 2003. Under U.S. GAAP, prior periods are not restated for the change in accounting policy and the effect of the change is charged to income, not unitholders’ equity. The effect of the change in accounting policy of $19,225,000 or $0.17 per unit basic and diluted was charged to income in 2003. | ||
| The following shows the effect of the change in accounting policy on the 2002 U.S. GAAP financial statements: |
| As reported: | ||||
| Net income under U.S. GAAP | $ | 73,246 | ||
| Net income per unit under U.S. GAAP | ||||
| Basic | $ | 0.81 | ||
| Diluted | $ | 0.81 | ||
| Pro forma amounts assumed SFAS 143 was applied retroactively: | ||||
| Net income under U.S. GAAP | $ | 81,134 | ||
| Net income per unit under U.S. GAAP | ||||
| Basic | $ | 0.90 | ||
| Diluted | $ | 0.90 | ||
| ARO beginning of year | $ | 42,123 | ||
| ARO end of year | $ | 73,493 | ||
| Prior to January 1, 2003, U.S. GAAP required the provision for abandonment costs to be recorded as a reduction of capital assets. | ||
| (g) | SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity’s approach to managing risk. |
| At December 31, 2003, $13,869,000 has been recorded as a current liability in respect of the fair value of crude oil and natural gas hedges outstanding at year end with a corresponding change in accumulated other comprehensive income. At December 31, 2002, $17,824,000 has been recorded as a liability in respect of fair value of crude oil and natural gas hedges outstanding at year end with a corresponding change in accumulated other comprehensive income. Of the liability, $12,666,000 has been classified as current and $5,158,000 has been classified as long term. These amounts will be recognized against crude oil and natural gas sales over the remaining terms of the related hedges. |
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| At December 31, 2003, $300,000 has been recorded as a current liability with respect to the ineffective portion of crude oil and natural gas hedges outstanding at year end, with a corresponding change to net income. At December 31, 2002, $960,000 has been recorded as a current liability with respect to the ineffective portion of crude oil and natural gas hedges outstanding at year end, with a corresponding change to net income. |
| At December 31, 2003, a current asset of $2,169,000 has been recorded in respect of the fair value of a foreign exchange swap outstanding at year end with a corresponding change in accumulated other comprehensive income. At December 31, 2002, a liability of $885,000 has been recorded with respect to the fair value of a foreign exchange swap outstanding at year end with a corresponding change in accumulated other comprehensive income. Of this liability, $351,000 has been classified as current and $534,000 has been classified as long term. |
| In 2003, Pengrowth terminated interest rate swaps at a total cost including accrued interest of $2,229,000. The cost has been recorded as an expense under Canadian GAAP. The unrealized hedging loss recorded in other comprehensive income related to the interest rate swaps, as at December 31, 2002 was $2,116,000. |
| (h) | In 2003, the Financial Accounting Standards Board (“FASB”) issued FIN 46 (Revised) “Consolidation of certain entities that are controlled through financial interests that indicate control (referred to as “variable interests”). Variable interests are the rights or obligations that convey economic gains or losses from changes in the values of an entity’s assets or liabilities. The holder of the majority of an entity’s variable interests will be required to consolidate the variable interest entity. Adopting the provisions of FIN 46 (Revised) had no impact on the U.S. GAAP financial statements. |
| In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. This Statement establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) because the financial instrument embodies an obligation of the issuer. Many of those instruments were previously classified as equity. Adopting the provisions of SFAS No. 150 had no impact on the U.S. GAAP financial statements. |
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Consolidated Statements of Income
The application of U.S. GAAP would have the following effect on net income as reported:
(Stated in thousands of Canadian Dollars, except per unit amounts)
| Years ended December 31 | 2003 | 2002 | ||||||
| Net income for the year, as reported | $ | 189,297 | $ | 56,955 | ||||
| Adjustments: | ||||||||
| Depletion and depreciation (a) | 26,999 | 26,363 | ||||||
| Effect of retroactive application with restatement under Canadian GAAP (f) | – | (7,888 | ) | |||||
| Compensation expense (c) | – | (1,224 | ) | |||||
| Unrealized gain (loss) on ineffective portion of oil and natural gas hedges (g) | 660 | (960 | ) | |||||
| Net income before cumulative effect of change in accounting policy under U.S. GAAP | $ | 216,956 | $ | 73,246 | ||||
| Cumulative effect of change in accounting policy (f) | 19,225 | – | ||||||
| Net income – U.S. GAAP | $ | 236,181 | $ | 73,246 | ||||
| Other comprehensive income: | ||||||||
| Unrealized gain on available for-sale-securities (d)(e) | – | 271 | ||||||
| Realized loss on available for-sale-securities (d)(e) | (271 | ) | – | |||||
| Realized gain on settlement of interest rate swaps (e)(g) | 2,116 | (2,116 | ) | |||||
| Unrealized hedging gains (losses) (e)(g) | 7,009 | (20,903 | ) | |||||
| Comprehensive income – U.S. GAAP | $ | 245,035 | $ | 50,498 | ||||
| Net income before cumulative effect of change in accounting policy under U.S. GAAP: | ||||||||
| Basic | $ | 1.87 | $ | 0.81 | ||||
| Diluted | $ | 1.86 | $ | 0.81 | ||||
| Net income – U.S. GAAP | ||||||||
| Basic | $ | 2.04 | $ | 0.81 | ||||
| Diluted | $ | 2.03 | $ | 0.81 | ||||
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Consolidated Balance Sheets
The application of U.S. GAAP would have the following effect on the Balance Sheets as reported:
Stated in thousands of Canadian Dollars
| As | Increase | |||||||||||
| December 31, 2003 | Reported | (Decrease) | U.S. GAAP | |||||||||
| Assets: | ||||||||||||
| Current portion of unrealized hedging gain (g) | $ | – | $ | 2,169 | $ | 2,169 | ||||||
| Capital assets (a) | 1,530,359 | (242,942 | ) | 1,287,417 | ||||||||
| $ | (240,773 | ) | ||||||||||
| Liabilities: | ||||||||||||
| Accounts payable and accrued liabilities (g) | $ | 54,196 | $ | 300 | $ | 54,496 | ||||||
| Current portion of unrealized hedging loss (g) | – | 13,869 | 13,869 | |||||||||
| Unitholders’ equity: | ||||||||||||
| Other comprehensive income (e)(g) | – | (11,700 | ) | (11,700 | ) | |||||||
| Trust Unitholders’ Equity (a) | 1,159,433 | (243,242 | ) | 916,191 | ||||||||
| $ | (240,773 | ) | ||||||||||
| December 31, 2002 | ||||||||||||
| Assets: | ||||||||||||
| Marketable securities (d) | $ | 1,906 | $ | 271 | $ | 2,177 | ||||||
| Capital assets (a)(f) | 1,493,047 | (362,659 | ) | 1,130,388 | ||||||||
| $ | (362,388 | ) | ||||||||||
| Liabilities: | ||||||||||||
| Accounts payable and accrued liabilities (g) | $ | 43,092 | $ | 960 | $ | 44,052 | ||||||
| Current portion of unrealized hedging loss (g) | – | 14,462 | 14,462 | |||||||||
| Long-term portion of unrealized hedging loss (g) | – | 6,363 | 6,363 | |||||||||
| Provision for abandonment costs (f) | 73,493 | (73,493 | ) | – | ||||||||
| Unitholders’ equity: | ||||||||||||
| Other comprehensive income (e)(g) | – | (20,554 | ) | (20,554 | ) | |||||||
| Trust Unitholders’ Equity (a)(f) | 1,073,164 | (290,126 | ) | 783,038 | ||||||||
| $ | (362,388 | ) | ||||||||||
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Additional disclosures required under U.S. GAAP
The components of accounts receivable are as follows:
| December 31, | 2003 | 2002 | ||||||
| Trade | $ | 52,663 | $ | 35,148 | ||||
| Prepaids | 9,759 | 5,084 | ||||||
| Other | 3,148 | 1,194 | ||||||
| $ | 65,570 | $ | 41,426 | |||||
The components of accounts payable and accrued liabilities are as follows:
| December 31, | 2003 | 2002 | ||||||
| Accounts payable | $ | 41,694 | $ | 29,806 | ||||
| Accrued liabilities | 12,802 | 14,246 | ||||||
| $ | 54,496 | $ | 44,052 | |||||
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APPENDIX D
FIVE YEAR REVIEW – PENGROWTH ENERGY TRUST CONSOLIDATED FINANCIAL RESULTS
(INCLUDED ON PAGES 98 THROUGH 99 OF THE PENGROWTH ENERGY TRUST 2003 ANNUAL REPORT)
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| Five Year Review | ||||||||||||||||||||
| Pengrowth Energy Trust Consolidated Financial Results | ||||||||||||||||||||
| (Stated in thousands of dollars, except per unit amounts) | ||||||||||||||||||||
| Years ended December 31 | 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||||||
| Financial (in thousands of dollars) | ||||||||||||||||||||
| Gross oil and gas revenue | $ | 682,795 | 482,301 | 469,929 | 416,228 | 252,408 | ||||||||||||||
| Crown royalties, net of incentives | $ | 108,325 | 73,833 | 65,203 | 69,594 | 27,671 | ||||||||||||||
| Freehold royalties and mineral taxes | $ | 6,580 | 6,774 | 6,757 | 6,994 | 4,215 | ||||||||||||||
| Operating costs | $ | 149,032 | 129,802 | 104,943 | 65,195 | 57,642 | ||||||||||||||
| Amortized injectant costs | $ | 32,541 | 44,330 | 47,448 | 32,463 | 13,964 | ||||||||||||||
| General and administrative | $ | 15,997 | 10,992 | 7,467 | 7,081 | 5,972 | ||||||||||||||
| Management fee | $ | 10,181 | 6,567 | 7,120 | 6,873 | 4,490 | ||||||||||||||
| Interest expense | $ | 18,153 | 15,213 | 18,806 | 17,354 | 10,882 | ||||||||||||||
| Capital taxes | $ | 1,798 | 483 | 2,659 | 1,830 | 1,190 | ||||||||||||||
| Depletion, depreciation and accretion | $ | 191,309 | 144,341 | 129,702 | 94,244 | 78,499 | ||||||||||||||
| Net Income | $ | 189,297 | 56,955 | 88,185 | 125,836 | 52,705 | ||||||||||||||
| Per unit | $ | 1.63 | 0.63 | 1.24 | 2.26 | 1.03 | ||||||||||||||
| Distributable cash(1) | $ | 313,415 | 194,458 | 215,787 | 218,340 | 128,172 | ||||||||||||||
| Per unit | $ | 2.68 | 2.07 | 3.01 | 3.79 | 2.49 | ||||||||||||||
| Total assets | $ | 1,673,718 | 1,552,651 | 1,270,208 | 1,113,503 | 880,217 | ||||||||||||||
| Per unit | $ | 13.51 | 14.04 | 15.45 | 17.44 | 16.41 | ||||||||||||||
| Long term debt | $ | 259,300 | 316,501 | 345,456 | 286,823 | 230,333 | ||||||||||||||
| Per unit | $ | 2.09 | 2.86 | 4.20 | 4.49 | 4.29 | ||||||||||||||
| Unitholders’ equity | $ | 1,159,433 | 1,073,164 | 828,540 | 650,267 | 564,271 | ||||||||||||||
| Per unit | $ | 9.36 | 9.71 | 10.07 | 10.18 | 10.52 | ||||||||||||||
| Net asset value at 10%(2) | $ | 1,124,433 | 1,239,322 | 914,970 | 926,899 | 705,159 | ||||||||||||||
| Per unit | $ | 9.08 | 11.21 | 11.13 | 14.52 | 13.15 | ||||||||||||||
| Return on average equity | 17.0 | % | 6.0 | % | 11.9 | % | 20.7 | % | 9.3 | % | ||||||||||
| Cash flow return on average equity | 28.1 | % | 20.5 | % | 29.2 | % | 36.0 | % | 22.7 | % | ||||||||||
| Average cost of debt capital | 5.1 | % | 4.6 | % | 5.2 | % | 6.8 | % | 6.2 | % | ||||||||||
| (1) | See Note 4 to the financial statements. | |
| (2) | Based on Proved plus Probable (P50) reserves discounted before income taxes |
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Pengrowth Energy Trust
Operating Results
Natural gas has been converted to equivalent barrels of oil at 6:1 unless otherwise stated
| Years ended December 31 | 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||||||
| Daily production | ||||||||||||||||||||
| Oil (bbl) | 23,337 | 19,914 | 19,726 | 17,599 | 17,570 | |||||||||||||||
| Gas (mcf) | 119,842 | 111,713 | 91,764 | 70,098 | 61,494 | |||||||||||||||
| Natural gas liquids (bbl) | 5,722 | 5,252 | 5,258 | 4,205 | 3,927 | |||||||||||||||
| Oil equivalent (boe) 6:1 | 49,033 | 43,785 | 40,320 | 33,581 | 31,821 | |||||||||||||||
| Total annual production (mboe) (6:1) | 17,897 | 15,982 | 14,717 | 12,291 | 11,615 | |||||||||||||||
| Average price | ||||||||||||||||||||
| Oil (per bbl) | $ | 40.64 | 38.06 | 37.26 | 40.37 | 26.73 | ||||||||||||||
| Gas (per mcf) | $ | 6.21 | 3.85 | 4.48 | 4.34 | 2.48 | ||||||||||||||
| Natural gas liquids (per bbl) | $ | 35.46 | 28.11 | 30.68 | 33.56 | 18.08 | ||||||||||||||
| Oil equivalent (per boe) 6:1 | $ | 38.15 | 30.18 | 31.93 | 33.87 | 21.73 | ||||||||||||||
| Property acquisitions ($millions) | $ | 126.5 | 389.3 | 277.1 | 179.6 | 141.8 | ||||||||||||||
| Capital expenditures ($millions) | $ | 85.7 | 55.6 | 74.0 | 59.8 | 17.7 | ||||||||||||||
| Reserves (Proved plus Probable) | ||||||||||||||||||||
| Reserves acquired in the year (mmboe) | N/A | 37.7 | 48.4 | 21.5 | 26.7 | |||||||||||||||
| Reserves at year-end (mmboe) | 184.4 | 214.8 | 210.5 | 183.0 | 176.6 | |||||||||||||||
| Acquisition cost per boe | $ | N/A | 10.33 | 5.72 | 8.34 | 5.31 | ||||||||||||||
| Stock Market Data | ||||||||||||||||||||
| Toronto Stock Exchange | ||||||||||||||||||||
| Trading volume | 97,393 | 51,110 | 41,249 | 21,494 | 14,457 | |||||||||||||||
| Trading value | $ | 1,617,668 | 753,684 | 734,382 | 394,244 | 204,125 | ||||||||||||||
| New York Stock Exchange | ||||||||||||||||||||
| Trading volume | 74,002 | 9,672 | ||||||||||||||||||
| Trading value (in U.S. $) | $ | 922,942 | 89,680 | |||||||||||||||||
| Market capitalization: | ||||||||||||||||||||
| Units outstanding | 123,874 | 110,562 | 82,240 | 63,852 | 53,639 | |||||||||||||||
| Year end unit price | $ | 21.25 | 14.73 | 14.22 | 19.20 | 15.50 | ||||||||||||||
| Total capitalization | $ | 2,632,315 | 1,628,583 | 1,169,454 | 1,225,962 | 831,410 | ||||||||||||||
| Toronto Stock Exchange | ||||||||||||||||||||
| Trust unit price: | ||||||||||||||||||||
| High | $ | 22.22 | 17.00 | 21.95 | 20.35 | 16.75 | ||||||||||||||
| Low | $ | 13.39 | 13.01 | 12.80 | 15.00 | 10.50 | ||||||||||||||
| Close | $ | 21.25 | 14.73 | 14.22 | 19.20 | 15.50 | ||||||||||||||
| New York Stock Exchange | ||||||||||||||||||||
| Trust unit price (in U.S. $): | ||||||||||||||||||||
| High | $ | 17.00 | 10.90 | |||||||||||||||||
| Low | $ | 9.07 | 8.40 | |||||||||||||||||
| Close | $ | 16.40 | 9.27 | |||||||||||||||||
| Cash on cash return: | ||||||||||||||||||||
| Yearly high price | 12.1 | % | 12.2 | % | 13.7 | % | 18.6 | % | 14.8 | % | ||||||||||
| Yearly low price | 20.0 | % | 15.9 | % | 23.5 | % | 25.2 | % | 23.7 | % | ||||||||||
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APPENDIX E
CORPORATE GOVERNANCE (INCLUDED ON PAGES 100 THROUGH 102 OF THE PENGROWTH ENERGY
TRUST 2003 ANNUAL REPORT)
Table of Contents
Corporate Governance
Corporate Responsibility
Pengrowth Energy Trust is in business to provide returns to Pengrowth unitholders through competitive acquisitions and effective management of our petroleum and natural gas properties. As a good corporate citizen we also recognize that economic performance is not the only criteria on which Pengrowth is evaluated. Pengrowth also supports a broad base of charitable organizations and is actively involved in the community.
Corporate Governance Practices
The Board of Directors of Pengrowth Corporation seeks to comply with prevailing standards for Corporate Governance in both Canada and the United States. The trust units of Pengrowth Energy Trust are listed on both the Toronto Stock Exchange and the New York Stock Exchange. Pengrowth Energy Trust is an issuer in Canada and a foreign issuer in the United States.
The Board of Directors of Pengrowth Corporation complies with the guidelines for effective Corporate Governance of the Toronto Stock Exchange and Pengrowth’s Corporate Governance practices in comparison with the TSX best practices are disclosed in Pengrowth’s annual proxy materials. These guidelines address the constitution of boards of directors and board committees as well as their functions, their independence from management and other means to promote sound Corporate Governance practices.
Pengrowth is also considering the application of recent legislative changes and the recommendations of influential organizations and commentators on effective Corporate Governance. Multilateral Instrument 58-201 on effective Corporate Governance was published for comment by the Canadian Securities administrators (the “CSA”) and will be considered for implementation in 2005. The impact of Multilateral Instrument 52-101 in respect of audit committee, Multilateral Instrument 52-109 in respect of the certification of disclosure on issuers’ annual and interim filings and National Instrument 51-101 in respect of standards of disclosure for oil and gas activities are being considered by Pengrowth. In the United States, the two most significant recent developments relate to the Sarbanes-Oxley Act of 2002 (“SOX”) and the Corporate Governance Listing Standards proposed by the New York Stock Exchange (“NYSE”). The SOX stipulates a certification process for financial results and internal financial statements by the Chief Executive Officer and Chief Financial Officer. The Corporate Governance Listings Standards establish mandatory Corporate Governance practices for issuers listed on the NYSE addressing issues such as board and committee independence and codes of conduct. Non-U.S. issuers listed on the NYSE are required only to comply with the audit committee requirement by July 31st, 2005 though such issuers much disclose either on their websites or in their annual reports any significant differences between their corporate governance practices and those required for U.S. issues.
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| The following are important elements of our current Corporate Governance practice: |
| • | The Board of Directors of the Corporation, Pengrowth Management Limited and senior management of the Corporation consider good Corporate Governance to be central to the effective and efficient operation of Pengrowth Energy Trust and Pengrowth Corporation. | |||
| • | Pengrowth Management Limited makes recommendations to the Board of Directors as to the strategic direction of Pengrowth Corporation and Pengrowth Energy Trust and as to acquisitions and divestitures. The Board of Directors considers these recommendations and assumes overall responsibility for the strategic direction of Pengrowth Corporation and Pengrowth Energy Trust. The Board of Directors of Pengrowth Corporation also considers management development and succession programs, financing proposals including the issuance of trust units and other securities as well as those matters which require Board approval; | |||
| • | Two members of the Board of Directors are considered related to the Corporation and/or Pengrowth Energy Trust by virtue of their appointment by Pengrowth Management Limited and other factors. The remainder (up to six) of the Directors are independent in that they have not worked for Pengrowth Corporation (nor Pengrowth Management Limited) nor have they material contracts with Pengrowth Corporation (nor Pengrowth Management Limited) nor have they received remuneration from Pengrowth Corporation (nor Pengrowth Management Limited), other than options or rights to acquire trust units, in excess of Directors’ fees payable by Pengrowth Corporation; | |||
| • | The Board of Directors has established a Corporate Governance and Compensation Committee. This committee is comprised of four independent directors and has activities which include: | |||
| – | adoption of a charter for Corporate Governance, which has been ratified by the Board of Directors; | |||
| – | development of procedures for assessing the effectiveness of the Board of Directors, committees and individual directors; | |||
| – | undertaking responsibility for evaluating the performance of Pengrowth Management Limited; | |||
| – | adoption of a business code of ethics and policies on disclosure and insider trading. | |||
| – | the independent members of the Board of Directors meet separately at meetings of the Board under the chairmanship of a lead director; | |||
| – | the audit committee of the Board of Directors is comprised entirely of independent members of the Board and communicates directly with the auditors of Pengrowth Corporation and Pengrowth Energy Trust; | |||
| – | the reserves committee of the Board has been appointed to review Pengrowth’s standards for reporting reserves for its portfolio of oil and natural gas properties. The reserves | |||
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| committee communicates directly with Gilbert Laustsen Jung Associates Ltd., Pengrowth Corporation’s independent engineers; |
| – | all stock option and stock rights plans have been approved by the unitholders of Pengrowth Energy Trust. |
Structure and Function
The Board of Directors has general corporate authority over the business and affairs of Pengrowth Corporation and derives its authority and respect to Pengrowth Energy Trust by virtue of the delegation of powers of the Trustee to Pengrowth Corporation as administrator in accordance with the Trust Indenture. In accordance with the Royalty Indenture, Trust Indenture and Unanimous Shareholders’ Agreement, the Trust unitholders and Royalty unitholders empowered the Trustee and Pengrowth Corporation to delegate authority to Pengrowth Management Limited. Pengrowth Management Limited derives its authority from the Management Agreement with both Pengrowth Corporation and Pengrowth Energy Trust. As a result neither Pengrowth Management Limited nor the Board of Directors has plenary authority over the business and affairs of Pengrowth Energy Trust or Pengrowth Corporation. In practice, Pengrowth Management Limited defers to the Board of Directors on all matters material to Pengrowth Corporation and Pengrowth Energy Trust.
The Board of Directors represents a cross-section of experience in matters of oil and natural gas, finance and directors’ responsibilities. Four of the six current members of the Board of Directors have been directors since the formation of Pengrowth Corporation and Pengrowth Energy Trust. Thomas A. Cumming has been a Director since April 2000 and Michael A. Grandin was elected a director at the April 23rd, 2002 Special and Annual Meeting.
Pengrowth Management Limited has broad discretion to administer and regulate the day-to-day operations of Pengrowth Energy Trust and Pengrowth Corporation and initiates acquisition and disposition activity.
Mandate of Computershare as Trustee
Computershare, as Trustee, has broad power over the administration and management of Pengrowth Energy Trust and the power to delegate those duties and responsibilities. This power is governed by the terms of the Trust Indenture between Pengrowth Corporation and Computershare, subject to the voting rights of the unitholders. All Trust unitholders and Royalty unitholders other than Computershare, are entitled to attend and vote upon all resolutions brought before meetings of the unitholders of Pengrowth Corporation on the basis of one vote for each trust unit.
102 Pengrowth Energy Trust • 2003 annual report
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APPENDIX F
PART II - CORPORATE GOVERNANCE (INCLUDED ON PAGES 12 THROUGH 21 OF THE
PENGROWTH ENERGY TRUST INFORMATION CIRCULAR – PROXY STATEMENT (DATED MARCH 15, 2004)
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PART II — CORPORATE GOVERNANCE
MANDATES OF THE TRUSTEE, THE MANAGER AND THE BOARD OF DIRECTORS
The Corporation holds petroleum and natural gas rights and other assets. Under the Royalty Indenture, a royalty was created representing 99% of the “Royalty Income”, which is payable to Royalty Unitholders. Pengrowth Trust was created for the purpose of issuing Trust Units to the public, facilitating an indirect investment in Royalty Units and other permitted investments under the Trust Indenture. Pengrowth Trust holds Royalty Units, interests in certain petroleum and natural gas facilities, cash and other assets. The Trust Units of Pengrowth Trust are listed on the Toronto Stock Exchange (the “TSX”) and on the New York Stock Exchange (the “NYSE”) and Pengrowth Trust is therefore subject to the corporate governance listing requirements of both exchanges.
Under the terms of the Trust Indenture, the Trustee is empowered to exercise those rights and privileges that could be exercised by a beneficial owner of the assets of Pengrowth Trust in respect of the administration and management of Pengrowth Trust. The Trustee is permitted to delegate certain of the powers and duties of the Trustee to any one or more agents, representatives, officers, employees, independent contractors or other persons. However, specific powers are delegated to the Corporation as “Administrator” under the Trust Indenture and the Trustee has granted broad discretion to the Manager to administer and regulate the day to day operations of Pengrowth Trust. The powers of the Trustee are also limited through the voting rights of Trust Unitholders.
Under the Management Agreement, the Manager is empowered to act as agent for Pengrowth Trust in respect of various matters, to execute documents on behalf of the Trustee and to make executive decisions which conform to general policies and general principles previously established by the Trustee. The Manager is empowered to undertake, on behalf of the Corporation and Pengrowth Trust, subject to the Royalty Indenture, all matters pertaining to the properties of the Corporation. See “Management Agreement”.
Under the Royalty Indenture, the Corporation makes all operating decisions with respect to the properties of the Corporation. Under the Trust Indenture, general powers have been delegated to the Corporation as the “Administrator” of Pengrowth Trust to perform those functions of the Trustee which are largely discretionary, subject to the powers and duties of the Manager. Additionally, specific powers have been delegated to the Corporation in relation to the offering of securities, the acquisition of facilities and other assets, the incurring of indebtedness, the granting of security and the determination of distributable income.
In accordance with the terms of the Unanimous Shareholder Agreement, all Royalty Unitholders other than the Trustee, and all Trust Unitholders are entitled to attend at, and vote upon, all resolutions brought before meetings of the Shareholders of the Corporation on the basis of one vote for each Unit held. Currently, the Unanimous Shareholder Agreement also provides that the Board of Directors shall consist of two nominees of the Manager and up to six directors who are elected by the Trust Unitholders of Pengrowth Trust. The Board of Directors meets a minimum of four times each year, once in each fiscal quarter. In addition, the Board of Directors meets at other times when matters requiring its approval are raised and the timing is such that it is not prudent or possible to await a regularly scheduled quarterly meeting. During 2003, eight regularly constituted Board of Directors meetings were held.
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BOARD INDEPENDENCE
The NYSE listing standards state that a majority of directors be independent. An independent director is defined as one who is independent of the Manager and is free from any interest or any business or other relationship which could, or could reasonably be perceived to, materially interfere with the director’s ability to act with a view to the best interests of the issuer, other than interests and relationships arising from shareholdings. In addition, the TSX Company Manual recommends that the board of directors of every issuer be constituted with a majority of individuals who qualify as “unrelated directors”. An unrelated director is a director who is independent of the Manager and is free from any interest and any business or other relationship which could, or could reasonably be perceived to, materially interfere with the director’s ability to act with a view to the best interest of Pengrowth Trust.
Five of seven directors recommended for election to the Board of Directors are independent directors under the NYSE requirements and five of the seven directors are unrelated. Mr. James S. Kinnear, who is Chairman, President and Chief Executive Officer of the Corporation as well as President and Chief Executive Officer of the Manager, is not independent of either entity and is a related director. Mr. Stanley H. Wong may be considered not to be independent and is a related director as he is the Manager’s additional appointee to the Board of Directors pursuant to the terms of the Unanimous Shareholder Agreement. However, Mr. Wong is neither engaged by the Manager nor by the Corporation and receives remuneration solely in his capacity as a director of the Corporation. The remainder of the directors are independent and unrelated, in that they have not worked for the Corporation (or the Manager) nor do they have material contracts with the Corporation (or the Manager) or receive remuneration from the Corporation (or the Manager), other than Trust Unit Options and Trust Unit Rights, in excess of director’s fees payable by the Corporation.
BOARD APPROVALS AND STRUCTURE
The Manager makes recommendations to the Board of Directors as to the strategic direction of the Corporation and Pengrowth Trust. The Board of Directors considers these recommendations and assumes overall responsibility for the strategic direction of the Corporation and Pengrowth Trust through the annual consideration of a strategic plan and budget. Criteria are approved by the Board of Directors for the acquisition and disposition of oil and natural gas properties and other permitted investments.
The Manager has general power under the Management Agreement to conduct acquisitions and dispositions and the operation of properties. Because of the structure created by the Trust Indenture, the Royalty Indenture and the Unanimous Shareholder Agreement, neither the Manager nor the Board of Directors has plenary authority over the businesses and affairs of Pengrowth Trust and the Corporation. The Trustee responds to directions from the Manager and from the Board of Directors (with respect to the Corporation as administrator of Pengrowth Trust) within the scope of the authority of the Trustee and the Trustee’s power to delegate.
The Board of Directors responds to recommendations brought forward by the Manager to the Board of Directors on material matters impacting the Corporation and Pengrowth Trust. Practically, the Manager defers to the Board of Directors in respect of all matters which may have a material impact upon the business and undertaking of the Corporation, Pengrowth Trust, the Royalty Unitholders or the Trust Unitholders. Reliance is placed upon independent engineering, legal and accounting consultants where appropriate.
The Board of Directors represents a cross-section of experience in matters of oil and gas, finance and directors’ responsibilities. Three of the seven nominated members of the Board of Directors have been directors since the formation of the Corporation and Pengrowth Trust. Thomas A. Cumming has been a director since April 2000 and Michael A. Grandin has been a director since April 2002. Michael S.
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Parrett and William R. Stedman have been nominated for election to the Board of Directors at the 2004 Annual Meeting. Mr. Parrett is a chartered accountant with extensive financial and management experience and Mr. Stedman is a professional engineer with extensive technical, financial and management experience.
BOARD COMMITTEES
The Audit Committee of the Board of Directors is currently comprised of four of the independent, unrelated directors. The Board of Directors has a Corporate Governance/Compensation Committee which is also comprised of four independent, unrelated directors. The Board of Directors has also formed a Reserves Committee comprised of two directors, one of whom is an independent, unrelated director, to review the assumptions and practices and results in respect to the preparation of independent reserve reports for the oil and gas assets of the Corporation and the reporting thereof. There are no other committees of the Board of Directors.
In respect of matters such as discussions concerning the Management Agreement or related party transactions, representatives of the Manager disclose their conflict of interest and absent themselves from discussions and voting.
STATEMENT OF CORPORATE GOVERNANCE PRACTICES
The Board of Directors and the Manager support the Guidelines for Corporate Governance (the “TSX Guidelines”) adopted by the TSX. On November 4, 2003, the NYSE adopted a number of changes to the standards for issuers listed on the NYSE, such as Pengrowth Trust. The changes to the NYSE listing standards are not mandatory for Pengrowth Trust, but any differences in Pengrowth Trust’s corporate governance practices and the NYSE rules must be disclosed by Pengrowth Trust in its annual 40F filing with the Securities and Exchange Commission in the United States. Certain provisions of SOX and certain rules adopted and proposed by the United States Securities and Exchanges Commission (“SEC”) pursuant to the requirements of SOX, which are applicable to Pengrowth Trust, also influence Pengrowth Trust’s approach to corporate governance. The Corporate Governance/Compensation Committee of the Board of Directors continues to monitor proposed amendments to Canadian and United States corporate governance practices and will take appropriate action in response to any new standards which are established.
Pengrowth is also considering the application of recent legislative changes and the recommendations of influential organizations and commentators on effective Corporate Governance. Multilateral Instrument 58-201 on effective Corporate Governance was published for comment by the Canadian Securities Administrators (the “CSA”) and will be considered for implementation in 2005. The impact of Multilateral Instrument 52-101 in respect of audit committee, Multilateral Instrument 52-109 in respect of certification of disclosure on issuers’ annual and interim filings and National Instrument 51-101 in respect of standards of disclosure for oil and gas activities are being considered by Pengrowth.
The Board of Directors, the Manager and senior management consider good corporate governance to be central to the effective and efficient operation of Pengrowth Trust and the Corporation. The Board of Directors has general corporate authority over the business and affairs of the Corporation and derives its authority in respect to Pengrowth Trust by virtue of the delegation of powers by the Trustee to the Corporation as “Administrator” in accordance with the Trust Indenture. In accordance with the Royalty Indenture, Trust Indenture and Unanimous Shareholder Agreement the Trust Unitholders and Royalty Unitholders empowered the Trustee and the Corporation to delegate authority to the Manager. The Manager derives its authority from the Management Agreement with both the Corporation and Pengrowth Trust. In practice, the Manager defers to the Board of Directors on all matters material to the Corporation and Pengrowth Trust.
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The following is a statement of the Corporation’s existing corporate governance practices with specific reference to the TSX Guidelines.
| 1. | The board of directors of every corporation should explicitly assume responsibility for the stewardship of the corporation and, as part of the overall stewardship responsibility, should assume responsibility for the following matters: |
| The Board of Directors is responsible for the overall stewardship of the Corporation and Pengrowth Trust and in setting corporate strategy and direction. The Board of Directors has overall responsibility for the management and supervision of the affairs of the Corporation and Pengrowth Trust. The Board of Directors has established administrative procedures which prescribe the rules governing the approval of transactions carried out in the course of the Corporation’s operations, the delegation of authority and the execution of documents on behalf of the Corporation. The Board of Directors reviews and approves various matters, including the appointment of corporate officers, as well as the annual capital and operating budgets and authorization of unbudgeted investments and divestitures above a specified dollar threshold. The Board of Directors’ expectations of management of the Corporation are communicated directly to management and through committees of the Board of Directors. More specifically, the Board of Directors assumes the following principal responsibilities: |
| (a) | adoption of a strategic planning process; |
| The Board of Directors considers management development and succession programs, strategic business developments such as significant acquisitions, and financing proposals including the issuance of Trust Units and other securities, as well as those matters requiring the approval of the Board of Directors. The Board of Directors conducts an annual strategic planning process. |
| As part of the strategic planning process conducted in 2003, senior officers of the Corporation and the general management of the Corporation held several meetings and put forward their views. This input from senior members of management was used as part of the background information reviewed by the Board of Directors to assist them in developing the Corporation’s strategic plan. |
| (b) | the identification of the principal risks of the corporation’s business and ensuring the implementation of appropriate systems to manage these risks; |
| The Board of Directors ensures that a system is in place to identify the principal risks to the Corporation and to monitor the process to manage such risks. The Audit Committee reviews and approves Management’s identification of principal financial risks and monitors the process to manage such risks. |
| (c) | succession planning, including appointing, training and monitoring senior management; |
| The Corporate Governance/Compensation Committee, in conjunction with the Manager, is responsible for appointing officers and other key employees on behalf of the Corporation, planning for the succession of the directors, officers and key employees; and reviewing the performance of senior management. |
| The Corporate Governance/Compensation Committee reviews the performance of senior members of management and also the total compensation paid to those individuals, including salary, bonus and options. The Committee also reviews the process and background information used to determine overall compensation in reference to industry data, performance and future objectives. |
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| (d) | a communications policy for the corporation; and |
| The Board of Directors has approved a Corporate Disclosure Policy to ensure timely, accurate, credible and balanced disclosure of material information in respect of Pengrowth Trust and the Corporation. The policy in place outlines the procedures and practical guidelines for the consistent, transparent, regular and timely public disclosure and dissemination of material and non-material information about the Corporation and Pengrowth Trust. Under the policy, a Disclosure Policy Committee has been established by the Board of Directors and includes the Chief Executive Officer, Chief Financial Officer, Lead Director and Corporate Secretary. It is this committee’s responsibility to monitor the effectiveness of and compliance with the Corporate Disclosure Policy and educate directors, officers and employees as to disclosure issues. |
| The Corporate Disclosure Policy has been provided to all staff to ensure employees are aware of the procedures in place regarding information being disclosed to the public. |
| (e) | the integrity of the corporation’s internal control and management information systems. |
| The Audit Committee: (a) monitors the integrity of the Corporation’s financial reporting process and systems of internal controls regarding finance, accounting, and legal compliance; (b) monitors the independence and performance of the Corporation’s independent auditors; and (c) provides an avenue of communication among the independent auditors, management and the Board of Directors. |
| The Audit Committee has approved a process that will be used to review management’s internal controls and procedures. |
| In order to comply with Section 404 of the SOX, which involves the Corporation’s internal control over financial reporting, management is reviewing and testing the company’s internal controls over financial reporting. The Board of Directors is provided with regular updates from management on this process. This process needs to be complete and in place for year end 2005 reporting. However, it is management’s intention to complete the review in 2004. |
| 2. | The board of directors of every corporation should be constituted with a majority of individuals who qualify as unrelated directors. An unrelated director is a director who is independent of management and is free from any interest and any business or other relationship which could, or could reasonably be perceived to, materially interfere with the director’s ability to act with a view to the best interests of the Corporation, other than interests and relationships arising from shareholding. A related director is a director who is not an unrelated director. If the corporation has a significant shareholder, in addition to a majority of unrelated directors, the board should include a number of directors who do not have interests in or relationships with either the corporation or the significant shareholder and which fairly reflects the investment in the corporation by Shareholders other than the significant shareholder. A significant shareholder is a shareholder with the ability to exercise a majority of the votes for the election of the board of directors. |
| The Board of Directors is presently comprised of six members, four of whom are independent and unrelated and two are appointments of the Manager, one of whom is the President, Chairman and Chief Executive Officer of the Corporation. |
| The Manager is entitled to appoint two members to the Board of Directors in accordance with the Management Agreement. The balance are to be appointed by the Trust Unitholders. |
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| The two new nominees to the Board of Directors would also be considered independent and unrelated. |
| 3. | The application of the definition of “unrelated director” to the circumstances of each individual director should be the responsibility of the board which will be required to disclose on an annual basis whether the board has a majority of unrelated directors, in the case of a corporation with a significant shareholder, whether the board is constituted with the appropriate number of directors which are not related to either the corporation or the significant shareholder. Management directors are related directors. The board will also be required to disclose on an annual basis the analysis of the application of the principles supporting this conclusion. |
| The Board of Directors is presently composed of a majority of unrelated directors and will be comprised of a majority of unrelated directors upon election of the directors proposed at the Shareholder Meeting: Thomas A. Cumming – unrelated director Michael A. Grandin – unrelated director James S. Kinnear – related director (Chairman, President and Chief Executive Officer) Francis G. Vetsch – retiring unrelated director Michael S. Parrett – unrelated director nominee William R. Stedman – unrelated director nominee Stanley H. Wong – related director (appointed by the Manager*) John B. Zaozirny – unrelated director (Lead Director) |
| * | Although Mr. Wong is appointed by the Manager, he holds no position with the Manager and has not had a financial connection to the Manager for more than 10 years. |
| 4. | The board of directors of every corporation should appoint a committee of directors composed exclusively of outside, i.e., non-management, directors, a majority of whom are unrelated directors, with the responsibility for proposing to the full board new nominees to the board and for assessing directors on an ongoing basis. |
| The Corporate Governance/Compensation Committee is presently composed of four directors, all of whom are independent directors. This committee’s responsibilities include proposing to the Board of Directors new nominees to the Board of Directors and assessing each director’s performance on an ongoing basis. In assessing new nominees, the Corporate Governance/Compensation Committee seeks to ensure that there is a sufficient range of skills, expertise and experience to ensure that the Board of Directors can carry out its mandate and functions effectively. The Corporate Governance/Compensation Committee receives and evaluates suggestions for candidates from individual directors, the President and Chief Executive Officer and from professional search organizations. During 2003 the Corporate Governance/Compensation Committee initiated a search process to seek two new directors of the Corporation, one with financial expertise and the second with technical/engineering expertise. Many candidates were considered and ultimately Korn/Ferry International were retained resulting in the two nominees proposed for election at the Shareholders Meeting. |
| 5. | Every board of directors should implement a process to be carried out by the nominating committee or other appropriate committee for assessing the effectiveness of the board as a whole, the committees of the board and the contribution of individual directors. |
| The Corporate Governance/Compensation Committee is responsible for assessing the effectiveness of the Board of Directors, its committees and individual directors. The Corporate Governance/Compensation Committee is also responsible for evaluating the performance of the |
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| Manager and, if necessary, negotiating the Management Agreement and making recommendations to the Trust Unitholders as to the Manager and the terms of the Management Agreement. |
| The Corporate Governance/Compensation Committee has developed an Annual Effectiveness Survey which includes evaluating board responsibility, board operations and board effectiveness. The Survey is completed by each Director and submitted anonymously. The collated results are then reviewed by the President and Lead Director. During 2003, the Corporate Governance/Compensation Committee negotiated a new Management Agreement with the Manager. |
| 6. | Every corporation, as an integral element of the process for appointing new directors, should provide an orientation and education program for new recruits to the board. |
| The Corporate Governance/Compensation Committee is responsible for procedures for the orientation and education of new board members concerning their role and responsibilities and for the continued development of existing members of the Board of Directors. Materials have been prepared for review by new directors in respect of the structure, business and results of Pengrowth Trust. |
| 7. | Every board of directors should examine its size and, with a view to determining the impact of the number upon effectiveness, undertake where appropriate, a program to reduce the number of directors to a number which facilitates more effective decision making. |
| A board of directors must have enough directors to carry out its duties efficiently while presenting a diversity of views and experiences. The Board of Directors currently has six members. The size of the Board of Directors and criteria for new directors are reviewed by the Corporate Governance/Compensation Committee and suitable candidates are identified. |
| Over the past year the Corporte Governance/Compensation Committee has reviewed the size of the Board of Directors, the experience of existing members and the increasing time commitments required of Directors. Once this review was complete criteria were set for new directors including a requirement for additional financial expertise and for additional technical expertise to replace the expertise of Mr. Francis G. Vetsch who has declined to stand for reelection to the Board. After an extensive search by the Committee and the President and Chief Executive Officer suitable candidates were identified and brought forward to the Board of Directors. The names of two new director nominees are being put forward for approval at the Shareholders Meeting. |
| 8. | The board of directors should review the adequacy and form of the compensation of directors and ensure the compensation realistically reflects the responsibilities and risk involved in being an effective director. |
| The Corporate Governance/Compensation Committee reviews and makes recommendations to the Board of Directors on the adequacy and form of the compensation of directors and the compensation to be paid to committee members and to the lead director based upon comparable available industry data. |
| 9. | Committees of the board of directors should generally be composed of outside directors, a majority of whom are unrelated directors, although some board committees, such as the executive committee, may include one or more inside directors. |
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| The Board of Directors annually appoints members to its committees. The committees presently established by the Board of Directors are composed as follows: |
| Audit Committee | Thomas A. Cumming, Chairman | unrelated director | ||
| John B. Zaozirny | unrelated director | |||
| Francis G. Vetsch* | unrelated director | |||
| Michael A. Grandin | unrelated director | |||
| Corporate Governance/ | John B. Zaozirny, Chairman | unrelated director | ||
| Compensation Committee | Michael A. Grandin | unrelated director | ||
| Thomas A. Cumming | unrelated director | |||
| Francis G. Vetsch* | unrelated director | |||
| Reserves Committee | Francis G. Vetsch* | unrelated director | ||
| Stanley H. Wong | related director |
| * | Mr. Francis G. Vetsch has advised the Board of Directors that he does not propose to stand for re-election. |
| In addition, the Board of Directors has established a Disclosure Policy Committee that includes: the lead director – John B. Zaozirny – unrelated director, the Chief Executive Officer – James S. Kinnear – related director, Chief Financial Officer – Robert B. Hodgins and Corporate Secretary – Charles V. Selby. |
| 10. | Every board of directors should expressly assume responsibly for, or assign to a committee of directors the general responsibility for, developing the corporation’s approach to governance issues. This committee would, amongst other things, be responsible for the corporation’s response to these governance guidelines. |
| The Corporate Governance/Compensation Committee is responsible for corporate governance issues and the implementation of the TSX Guidelines. The Corporate Governance/Compensation Committee is responsible for reviewing and providing recommendations for improvement to the Board of Directors with respect to all aspects of corporate governance. The Corporation has in place a Code of Business Conduct and a Code of Ethics for all employees and agents of the Corporation; Terms of Reference for the Corporate Governance/Compensation Committee; a Corporate Governance Policy for the Board of Directors; Terms of Reference for the Chairman of the Board of Directors and the lead director; and a Charter for the Audit Committee. |
| The Corporate Governance/Compensation Committee reviews new corporate governance information on an ongoing basis to ensure they are following best practices suggested in this area. |
| 11. | The board of directors, together with the Chief Executive Officer, should develop position descriptions for the board and for the Chief Executive Officer, involving the definition of the limits to management’s responsibilities. In addition, the board should approve or develop the corporate objectives which the Chief Executive Officer is responsible for meeting. |
| The Board of Directors has adopted guidelines for the responsibilities of the Board of Directors and has in place Terms of Reference for the positions of lead director and Chairman of the Board of Directors. The responsibilities of the Manager are set out in the Management Agreement. The Corporate Governance/Compensation Committee will set annual performance objectives in discussions with the Manager in conjunction with the Board of Directors’ strategic planning and budgeting processes. |
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| 12. | Every board of directors should have in place appropriate structures and procedures to ensure that the board can function independently of management. An appropriate structure would be to (i) appoint a chair of the board who is not a member of management with responsibility to ensure the board discharges its responsibilities or (ii) adopt alternate means such as assigning this responsibility to a committee of the board or to a director, sometimes referred to as the “lead director”. Appropriate procedures may involve the board meeting on a regular basis without management present or may involve expressly assigning the responsibility for administering the board’s relationship to management to a committee of the board. |
| The Board of Directors derives its authority with respect to Pengrowth Trust from the duties delegated to the Corporation as “Administrator” by the Trustee in accordance with the Trust Indenture. The Trustee also delegates certain powers to the Manager in accordance with the terms of the Management Agreement. In practice, the Manager defers to the Board of Directors on all material matters. The Board of Directors is composed of a majority of independent directors. In matters that require independence of the Board of Directors, only the independent directors participate in the decision making and evaluation. |
| The Board of Directors have appointed a lead director who is not a member of management. The Board of Directors meets independently of management at all board and committee meetings. |
| 13. | The audit committee of every board of directors should be composed only of outside directors. The roles and responsibilities of the audit committee should be specifically defined so as to provide appropriate guidance to audit committee members as to their duties. The audit committee should have direct communication channels with the internal and external auditors to discuss and review specific issues as appropriate. The audit committee duties should include oversight responsibility for management reporting on internal control. While it is management’s responsibility to design and implement an effective system of internal control, it is the responsibility of the audit committee to ensure that management has done so. |
| The Audit Committee is composed of four independent, unrelated directors. The mandate of the Audit Committee is set forth in the Audit Committee Charter, which the Board of Directors adopted July 30, 2001. The charter directs the Audit Committee to: (a) monitor the integrity of the company’s financial reporting process and systems of internal controls regarding finance, accounting, and legal compliance; (b) monitor the independence and performance of the company’s independent auditors; and (c) provide an avenue of communication among the independent auditors, management and the Board of Directors. |
| The Board of Directors notes that the Canadian Securities Administrators have recently adopted Multilateral Instrument 52-110 –Audit Committees (“MI 52-110”) which will become effective for Pengrowth Trust on the earlier of its next annual unitholders’ meeting and July 1, 2005. The Board of Directors is currently reviewing Pengrowth Trust’s practices to determine compliance to MI 52-110. The Board of Directors expects that, given its historical focus on corporate governance, only minor changes will be necessary. |
| The Audit Committee meets independently with the external auditor of the Corporation on a regular basis. |
| 14. | The board of directors should implement a system which enables an individual director to engage an outside adviser at the expense of the corporation in appropriate circumstances. The engagement of the outside advisor should be subject to the approval of an appropriate committee of the board. |
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| The Corporate Governance Policy of the Board of Directors permits directors to engage outside advisors at the Corporation’s expense with the approval of the Board of Directors. |
The Board of Directors has approved the following charters and policies in respect to corporate governance:
| DATE OF APPROVAL BY THE | ||||
| CHARTER/POLICY | BOARD OF DIRECTORS | |||
| 1. | Policy on Trading in Securities by Directors, Officers and Employees | October 30, 2003 | ||
| 2. | Corporate Disclosure Policy | March 3, 2003 | ||
| 3. | Code of Business Ethics | November 19, 2002 | ||
| 4. | Authority Levels | November 19, 2002 | ||
| 5. | Terms of Reference — Corporate Governance/Compensation Committee | July 30, 2002 | ||
| 6. | Corporate Governance Policy | July 30, 2002 | ||
| 7. | Terms of Reference Chairman of the Board of Directors | July 30, 2002 | ||
| Terms of Reference Lead Director | ||||
| 8. | Audit Committee Charter | July 30, 2001 | ||
| 9. | Internet Policy | July 21, 1999 |
OTHER MATTERS
The Manager knows of no amendment, variation or other matter to come before the Meetings other than the matters referred to in the Notices of Meetings. If any other matter properly comes before the Meetings, however, the enclosed proxies will be voted on such matter in accordance with the best judgment of the person or persons voting the proxies.
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APPENDIX G
OIL AND GAS PRODUCING ACTIVITIES PREPARED IN ACCORDANCE WITH SFAS NO. 69 –
“DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES”.
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SUPPLEMENTAL INFORMATION — OIL AND GAS PRODUCING ACTIVITIES
(unaudited)
The following disclosures have been prepared in accordance with SFAS No. 69 — “disclosures about Oil and Gas Producing Activities.”:
OIL AND GAS RESERVES
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
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.
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 the Trust’s estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Trust’s share of future production from Canadian reserves to be materially different from that presented.
Subsequent to December 31, 2003 no major discovery or other favorable 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
The following table sets forth revenue and direct cost information relating to the Trust’s oil and gas producing activities for the years ended December 31.
| (thousands of dollars) | 2003 | 2002 | ||||||
| Revenue | ||||||||
| Sales | $ | 577,616 | $ | 408,630 | ||||
| Deduct | ||||||||
| Production costs | 143,453 | 125,558 | ||||||
| Amortization of injectant costs | 32,541 | 44,330 | ||||||
| Technical support and other | 5,579 | 4,244 | ||||||
| Depletion, depreciation and amortization and valuation provision | 158,271 | 112,511 | ||||||
| Results of operations from producing activities | $ | 237,772 | $ | 121,987 | ||||
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| 1. | The costs in this schedule exclude corporate overhead, interest expense and other operating costs which are not directly related to producing activities. |
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
Costs incurred in oil and gas producing activities for the years ended December 31 are as follows:
| (thousands of dollars) | 2003 | 2002 | ||||||
| Property Acquisition Costs | ||||||||
| Proved | $ | 122,964 | $ | 391,761 | ||||
| Development Costs | 85,718 | 55,631 | ||||||
| Injectant Costs | 23,037 | 15,107 | ||||||
| $ | 231,719 | $ | 462,499 | |||||
Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.
Development costs include the costs of drilling and equipping development wells and facilities to extract, treat and gather and store oil and gas.
Injectants (mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated as 30 months.
General and administrative costs are not capitalized other than to the extent they are directly related to a successful acquisition, or to the extent of the Trust’s working interest in exploration or development projects to which overhead fees can be recovered from partners. Overhead fees are not charged on 100% owned projects.
There were no oil and gas property costs not being amortized in any of the years presented.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
The capitalized costs and related accumulated depreciation, depletion and amortization, including impairments, relating to the Trust’s oil and gas exploration, development and producing activities at December 31 consist of:
| (thousands of dollars) | 2003 | 2002 | ||||||
| Proved oil and gas properties | $ | 2,305,462 | $ | 1,976,802 | ||||
| Less accumulated depletion, depreciation and amortization | (1,018,045 | ) | (846,415 | ) | ||||
| Net capitalized costs | $ | 1,287,417 | $ | 1,130,388 | ||||
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OIL AND GAS RESERVE INFORMATION
All of the Trust’s proved oil, natural gas liquids, and natural gas reserves are located in Canada, primarily in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. The Trust’s proved developed and undeveloped reserves after deductions of royalties are summarized below:
| Crude Oil and | ||||||||
| Natural Gas | Natural | |||||||
| Liquids | Gas | |||||||
| MMbbls | Bcf | |||||||
NET PROVED DEVELOPED AND UNDEVELOPED RESERVES AFTER ROYALTIES | ||||||||
End of year 2001 | 90.9 | 330.3 | ||||||
| Revision of previous estimates | (3.0 | ) | (22.1 | ) | ||||
| Purchase of reserves in place | 13.4 | 73.2 | ||||||
| Sales of reserves in place | (4.2 | ) | (16.5 | ) | ||||
| Discoveries and extensions | 0.1 | 3.2 | ||||||
| Production | (7.4 | ) | (32.1 | ) | ||||
End of year 2002 | 89.8 | 336.0 | ||||||
| Revision of previous estimates | (4.6 | ) | (33.8 | ) | ||||
| Purchase of reserves in place | 0.3 | 0.6 | ||||||
| Sales of reserves in place | (0.2 | ) | (0.6 | ) | ||||
| Discoveries and extensions | 0.1 | 3.0 | ||||||
| Production | (8.1 | ) | (33.8 | ) | ||||
End of year 2003 | 77.3 | 271.4 | ||||||
NET PROVED DEVELOPED RESERVES AFTER ROYALTIES | ||||||||
| End of year 2001 | 65.9 | 231.6 | ||||||
| End of year 2002 | 66.6 | 233.2 | ||||||
| End of year 2003 | 60.6 | 219.9 | ||||||
| Notes: | ||||
| 1. | Net after royalty reserves are the Trust’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 described by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the independent engineering consultants of the Trust.It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Trust 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 the Trust’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, 2003 was based on a crude price of $38.77/bbl and natural gas price of $6.13/mcf. The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2002 was based on the Trust’s crude oil price of $42.58 /bbl and natural gas price of $5.58 /mcf.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES
The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Trust’s crude oil and natural gas reserves at December 31, for the years presented.
| (millions of dollars) | 2003 | 2002 | ||||||
| Future cash inflows | $ | 4,797 | $ | 5,621 | ||||
| Future costs | ||||||||
| Future production and development costs | (2,034 | ) | (2,108 | ) | ||||
| Future net cash flows | 2,763 | 3,513 | ||||||
| Deduct: 10% annual discount factor | (1,159 | ) | (1,571 | ) | ||||
| Standardized measure of discounted future net cash flows | $ | 1,604 | $ | 1,942 | ||||
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CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES
The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the years presented.
| (millions of dollars) | 2003 | 2002 | ||||||
| Future discounted net cash flows at beginning of year | $ | 1,942 | $ | 897 | ||||
| Sales and transfer, net of production costs | (395 | ) | (262 | ) | ||||
| Net change in sales and transfer prices, net of development and production costs | (115 | ) | 733 | |||||
| Extensions, discoveries and improved recovery, net of related costs | 7 | 9 | ||||||
| Revisions of quantity estimates | (134 | ) | (89 | ) | ||||
| Accretion of discount | 194 | 90 | ||||||
| Sales of reserves in place | (4 | ) | (92 | ) | ||||
| Purchase of reserves in place | 5 | 432 | ||||||
| Changes in timing of future net cash flows and other | 104 | 224 | ||||||
| End of Year | $ | 1,604 | $ | 1,942 | ||||
| Note: | ||||
| 1. | The schedules above are calculated using year-end prices, costs, statutory 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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EXHIBITS
| Exhibit No. | Description | |
| 1 | Consent of KPMG LLP, independent registered public accounting firm | |
| 2 | Consent of Gilbert Laustsen Jung Associates Ltd., independent petroleum consultants | |
| 3 | Consent of Bennett Jones LLP, legal counsel | |
| 4 | Consent of Vinson & Elkins L.L.P., legal counsel |