o | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934. | |||
þ | ANNUAL REPORT PURSUANT TO SECTION13(a) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended:December 31, 2005 | Commission File Number:1-31253 |
(Province or other jurisdiction of incorporation or organization)
1311 | None | |
(Primary Standard Industrial | (I.R.S. Employer | |
Classification Code Number) | Identification Number) |
Calgary, Alberta Canada T2P 4H4
(403) 233-0224
(Address and telephone number of Registrant’s principal executive offices)
2300 First City Tower, 1001 Fannin
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)
Title of each class | Name of each exchange on which registered | |
Class A Trust Units | New York Stock Exchange |
þ Annual information form | þ Audited annual financial statements |
Yes o | No þ |
Yes þ | No o |
Appendix | Documents | |
A | Pengrowth Energy Trust Annual Information Form for the year ended December 31, 2005. | |
B | Management’s Discussion and Analysis (included on pages 54 through 80 of the Pengrowth Energy Trust 2005 Annual Report). | |
C | Consolidated Financial Statements of Pengrowth Energy Trust, including note 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 115 through 119 of the Pengrowth Energy Trust 2005 Annual Report). | |
E | Corporate Governance (included on pages 48 through 53 of the Pengrowth Energy Trust 2005 Annual Report). | |
F | Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”. |
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Date: March 29, 2006 | PENGROWTH ENERGY TRUST by its Administrator PENGROWTH CORPORATION | |||
By: | /s/ James S. Kinnear | |||
James S. Kinnear | ||||
Chairman, President and Chief Executive Officer |
GLOSSARY OF TERMS AND ABBREVIATIONS | 1 | |||
CONVERSION | 4 | |||
PRESENTATION OF OUR FINANCIAL INFORMATION | 4 | |||
PRESENTATION OF OUR RESERVE INFORMATION | 4 | |||
FORWARD-LOOKING STATEMENTS | 5 | |||
PENGROWTH ENERGY TRUST | 6 | |||
GENERAL DEVELOPMENT OF PENGROWTH TRUST | 6 | |||
Organization and Structure | 6 | |||
Business Strategy and Strengths | 7 | |||
Historical Development | 8 | |||
Recent Acquisitions, Financings and Developments | 11 | |||
Trends | 12 | |||
PENGROWTH MANAGEMENT LIMITED | 13 | |||
Business | 13 | |||
Management Agreement | 13 | |||
Management Agreement Second Term | 15 | |||
PENGROWTH CORPORATION — OPERATIONAL INFORMATION | 15 | |||
Principal Properties | 16 | |||
Additional Information Relating to Reserves Data | 32 | |||
Finding, Development and Acquisition Costs | 34 | |||
FD&A Costs — Company Interest Reserves | 35 | |||
Other Oil and Gas Information | 35 | |||
Production | 38 | |||
Replacement of Properties | 40 | |||
Borrowing | 40 | |||
TRUST UNITS | 41 | |||
The Trust Indenture | 41 | |||
The Trustee | 41 | |||
Redemption Right | 42 | |||
Voting at Meetings of Pengrowth Trust | 42 | |||
Voting at Meetings of Pengrowth Corporation | 42 | |||
Termination of Pengrowth Trust | 42 | |||
Unitholder Limited Liability | 43 | |||
Special Voting Unit | 43 | |||
Trust Unit Reclassification | 43 | |||
Background | 43 | |||
THE ROYALTY INDENTURE | 48 | |||
Royalty Units | 48 | |||
The Royalty | 49 | |||
The Trustee | 49 | |||
EXCHANGEABLE SHARES | 50 | |||
DISTRIBUTIONS | 50 |
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INDUSTRY CONDITIONS | 51 | |||
Government Regulation | 51 | |||
Pricing and Marketing — Oil | 51 | |||
Pricing and Marketing — Natural Gas | 51 | |||
Pricing and Marketing — Natural Gas Liquids | 52 | |||
The North American Free Trade Agreement | 52 | |||
Provincial Royalties and Incentives | 52 | |||
Environmental Regulation | 54 | |||
MARKET FOR SECURITIES | 55 | |||
Class A Trust Units | 55 | |||
Class B Trust Units | 55 | |||
DIRECTORS AND OFFICERS | 56 | |||
Directors and Officers of Pengrowth Management Limited | 56 | |||
Principal Holders of Shares of Pengrowth Management | 56 | |||
Directors and Officers of the Corporation | 57 | |||
Corporate Cease Trade Orders or Bankruptcies | 58 | |||
Personal Bankruptcies | 58 | |||
Penalties or Sanctions | 58 | |||
AUDIT COMMITTEE | 59 | |||
Principal Accountant Fees and Services | 60 | |||
Pre-approval Policies and Procedures | 60 | |||
RISK FACTORS | 60 | |||
CONFLICTS OF INTEREST | 71 | |||
LEGAL PROCEEDINGS | 72 | |||
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS | 72 | |||
INTERESTS OF EXPERTS | 72 | |||
AUDITORS, TRANSFER AGENT AND REGISTRAR | 72 | |||
MATERIAL CONTRACTS | 73 | |||
CODE OF ETHICS | 73 | |||
OFF-BALANCE SHEET ARRANGEMENTS | 73 | |||
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS | 73 | |||
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE | 73 | |||
ADDITIONAL INFORMATION | 75 |
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APPENDIX A | A-1 | |||
Report On Reserves Data By Independent | ||||
Qualified Reserves Evaluations On Form 51-101F2 | ||||
APPENDIX B | B-1 | |||
Report Of Management And Directors On | ||||
Oil And Gas Disclosure On Form 51-101F3 | ||||
APPENDIX C | C-1 |
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• | Board of Directorsrefers to the board of directors of the Corporation; | ||
• | Computersharerefers to Computershare Trust Company of Canada; | ||
• | Corporationrefers to Pengrowth Corporation, the administrator of the Trust; | ||
• | Pengrowth, we, usandourrefers to the Trust and the Corporation on a consolidated basis; | ||
• | Managerrefers to Pengrowth Management Limited, the manager of the Trust and the Corporation; | ||
• | Reclassificationmeans the reclassification of our outstanding Trust Units as Class B Trust Units and the conversion of Class B Trust Units held by non-residents of Canada to Class A Trust Units which occurred on July 27, 2004; | ||
• | Trustrefers to Pengrowth Energy Trust; | ||
• | Trust Units, when used in reference to any time before 5:00 p.m. Eastern Daylight Time on July 27, 2004, refers to the Trust Units of the Trust as they existed before the Reclassification, and when used in reference to any time after 5:00 p.m. Eastern Daylight Time on July 27, 2004, refers to the Class A Trust Units and the Class B Trust Units of the Trust as well as the Trust Units of the Trust that remain as they existed before the Reclassification; and | ||
• | Unitholdersrefers to holders of Trust Units issued by the Trust. |
• | Company Gross InterestorPengrowth Gross Interestrefers to the Working Interest share of reserves prior to the deduction of interests owned by others (burdens). Company Royalty Interest reserves are not included in the Company Gross Interest reserves; | ||
• | Company Net InterestorPengrowth Net Interestrefers to Pengrowth’s Working Interest share of production or reserves, as the case may be, after the deduction of royalties and including Company Royalty Interest reserves, and, with respect to land and wells, refers to Pengrowth’s Working Interest share therein; | ||
• | Company Royalty Interestrefers to an interest in production and payment that is based on the gross production at the wellhead. A royalty is paid in either cash or kind, but is paid on a value calculated at the wellhead; | ||
• | 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; | ||
• | GLJrefers to GLJ Petroleum Consultants Ltd., independent petroleum consultants, Calgary, Alberta; | ||
• | GLJ Reportrefers to the report prepared by GLJ dated February 17, 2006, having an effective date of December 31, 2005; |
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• | 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 Company Interestis equal to Company Gross Interest plus Company Royalty Interest.That is, the Working Interest share of production or reserves prior to the deduction of interests owned by others (burdens) plus the interest in production made from gross production or reserves at the wellhead; | ||
• | Pengrowth Total Proved Plus Probable Reservesmeans Company Interest share of the Total Proved Plus Probable Reserves; | ||
• | 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 2006 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 (e.g., proved, probable); | ||
• | 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 accumulations where a significant expenditure (e.g. 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. |
• | APImeans American Petroleum Institute; | ||
• | 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 |
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conversion 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; | ||
• | CBMrefers to coal bed methane; | ||
• | EORrefers to enhanced oil recovery; | ||
• | $Mand$MMrefers to thousands of dollars and millions of dollars, respectively; | ||
• | mmBtuandmmBtupdrefers to million British thermal units and million British thermal units per day respectively; | ||
• | mcf, mmcf, bcfandtcfrefers to thousands of cubic feet, millions of cubic feet, billions of cubic feet and trillions of cubic feet, respectively; | ||
• | mcfpdandmmcfpdrefers to thousands of cubic feet per day and millions of cubic feet per day respectively; | ||
• | NGLsrefers to natural gas liquids; | ||
• | NYSErefers to the New York Stock Exchange; and | ||
• | TSXrefers to the Toronto Stock Exchange. |
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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 | 6.29 | ||||
feet | metre | 0.305 | ||||
metre | feet | 3.281 | ||||
miles | kilometre | 1.609 | ||||
kilometre | miles | 0.621 | ||||
acres | hectares | 0.405 | ||||
hectares | acres | 2.471 |
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(1) | These properties were acquired on May 31, 2004 in an acquisition from Murphy Oil which had interests in oil and natural gas assets in Alberta and | |
(2) | These properties were acquired on April29, 2005 in the acquisition of Crispin. |
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• | 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. |
• | Properties to be acquired should be high quality, relatively long life and proven producing properties. The Corporation gives priority to properties with: |
o | low anticipated capital expenditures relative to the cash generation potential of the properties; | ||
o | relatively low operating costs or high netbacks; | ||
o | experienced, well regarded industry operators or where operatorship may be assumed by Pengrowth; | ||
o | favourable production history; | ||
o | upside potential through infill drilling, improved field operations and other development activities; | ||
o | relatively long reserve life; | ||
o | potential synergies with our current properties and areas of our core expertise; and | ||
o | low environmental and site remediation risk. |
• | 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. |
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PLANNED CAPITAL EXPENDITURES | $ MILLIONS | % OF TOTAL | ||||||
Drilling expenditures | 131 | 56 | ||||||
Facilities and maintenance | 64 | 27 | ||||||
Land and seismic | 21 | 9 | ||||||
Recompletions and workovers | 12 | 5 | ||||||
Other | 8 | 3 | ||||||
TOTAL | 236 | 100 | ||||||
Average daily production volume (boepd) | 54,000 - 56,000(1) | |||||||
Operating costs per boe | $ 11.00(2) | |||||||
1. | After the divestiture of approximately 1,300 boepd of production in the first quarter of 2006 comprised of volumes associated with previously disclosed purchase and sale agreements, as well as the divestment of approximately 1,000 boepd of production related to the Monterey transactions announced on January 12, 2006. The 2006 estimate excludes potential additions through acquisition. | |
2. | Assuming the production targets for 2006 are achieved. |
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• | two distinct 3-year terms with a declining fee structure in the second 3-year term; | ||
• | a base fee determined on a sliding scale: |
o | in the first three-year contract term: |
§ | 2 percent of the first $200 million of Income; and | ||
§ | 1 percent of the balance of Income over $200 million; and |
o | in the second three-year contract term: |
§ | 1.5 percent of the first $200 million of Income; and | ||
§ | 0.5 percent of the balance of Income over $200 million. |
• | a performance based fee based on total returns received by Unitholders which essentially compensates the Manager for total annual returns which average in excess of 8 percent per annum over a 3-year period; |
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• | a ceiling on total fees payable determined in reference to a percentage of the fees paid under the previous management agreement: 80 percent each year in the first three-year contract term and 60 percent 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; | ||
• | requirement for the Manager to pay certain expenses of the Corporation and the 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 the Manager; | ||
• | an annual bonus pool based on 10 percent of the Manager’s base fee and performance fee for employees of, and special consultants to, the 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 approximately 2/3 of the management fee paid during the first three-year contract term plus expenses of termination. |
• | reviewing and negotiating acquisitions for the Corporation and the Trust; | ||
• | providing written reports to the Board of Directors to keep the 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 the Corporation in connection with it acting as operator of certain of its properties; | ||
• | arranging for, and negotiating on behalf of, and in the name of, the Corporation all contracts with third parties for the proper management and operation of the properties of the Corporation; | ||
• | supervising, training and providing leadership to the employees and consultants of the Corporation and assisting in recruitment of key employees of the Corporation; | ||
• | arranging for professional services for the Corporation and the Trust; | ||
• | arranging for borrowings by the Corporation and equity issuances by the 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 the Corporation or the 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. |
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• | The amount of the termination fee payable to the Manager on termination of the Management Agreement effective June 30, 2006; | ||
• | The estimated cost of internal management to June 30, 2009 in the event of a termination of the Management Agreement effective June 30, 2006; | ||
• | The estimated maximum management fees that would be payable to the Manager over the final three years of the term of the Management Agreement; | ||
• | The advice of its financial advisor; | ||
• | The fee ceiling applicable during the final three years of the Management Agreement which will result in lower management fees in the second term of the Management Agreement ending June 30, 2009 as compared to the first term of the Management Agreement ending June 30, 2006; and | ||
• | The commitment by the Manager to certain key governance standards relating to the conduct of the affairs of the Trust and a continuing commitment to overall corporate governance practices (as such practices would apply to Pengrowth in an internalized management structure); and a further commitment to assist and work with the Board in establishing a plan for the orderly transition to a traditional corporate management structure at the end of the final term of the Management Agreement on June 30, 2009. |
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Forecast Prices and Costs
Company Interest | 2005 Actual | |||||||||||||||||||
Remaining | Reserve Life | Total Proved Plus | Value at | Oil Equivalent | ||||||||||||||||
Reserve Life | Index | Probable Reserves(2) | 10% Discount | Production(2) | ||||||||||||||||
(Years) | (Years) | (Mboe) | ($million) | (boepd) | ||||||||||||||||
Judy Creek BHL Unit | 50 | 11.9 | 36,820 | 538.1 | 8,847 | |||||||||||||||
Swan Hills Unit No.1 | 50 | 21.1 | 19,903 | 196.5 | 2,481 | |||||||||||||||
Weyburn Unit | 50 | 18.6 | 19,253 | 186.1 | 2,649 | |||||||||||||||
SOEP | 11 | 5.7 | 15,241 | 346.1 | 7,075 | |||||||||||||||
Judy Creek West BHL Unit | 50 | 23.1 | 9,160 | 81.1 | 1,415 | |||||||||||||||
Monogram Gas Unit | 36 | 8.7 | 6,265 | 120.6 | 2,517 | |||||||||||||||
McLeod River | 50 | 7.3 | 5,480 | 92.5 | 2,321 | |||||||||||||||
East Bodo | 50 | 28.3 | 5,252 | 31.5 | 542 | |||||||||||||||
Dunvegan Gas Unit No. 1 | 39 | 9.3 | 5,154 | 72.6 | 1,442 | |||||||||||||||
Twining | 45 | 10.3 | 4,390 | 63.9 | 1,360 | |||||||||||||||
Kaybob Notikewin Unit No. 1 | 40 | 12.8 | 4,366 | 53.6 | 1,048 | |||||||||||||||
Tangleflags | 18 | 6.8 | 4,344 | 22.8 | 1,806 | |||||||||||||||
Oak | 50 | 10.9 | 4,030 | 70.4 | 1,014 | |||||||||||||||
Quirk Creek | 35 | 11.9 | 3,574 | 42.7 | 807 | |||||||||||||||
Princess | 50 | 9.0 | 3,556 | 65.1 | 796 | |||||||||||||||
Enchant | 50 | 15.3 | 3,270 | 37.1 | 684 | |||||||||||||||
Rigel | 21 | 6.7 | 3,150 | 73.4 | 1,625 | |||||||||||||||
Other(1) | 50 | 8.9 | 66,188 | 1,110.4 | 20,928 | |||||||||||||||
Total | 50 | 10.5 | 219,396 | 3,204.5 | 59,357 |
1. | “Other” includes the Corporation’s working and royalty interest in approximately 100 other properties. 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. | The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. |
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a. | analysis of drilling, geological, geophysical and engineering data; | ||
b. | the use of established technology; and | ||
c. | specified economic conditions. |
a. | Proved Reserves are 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. | ||
b. | Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
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• | 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. | the GLJ Report does not estimate general and administrative expenses, interest, management fees and holdbacks; | ||
b. | the GLJ Report does not estimate all abandonment or any reclamation liabilities; | ||
c. | for purposes of calculating distributable income, the 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 had been 30 months and was revised to 24 months for 2005 onward. The GLJ Report includes the full cost of purchased injection fluids ($34.7 million in 2005) in operating costs in the year incurred; and | ||
d. | the Corporation withholds certain amounts from distributable cash to fund capital. |
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OIL AND GAS RESERVES | ||||||||||||||||||||||||||||||||||||
Light and Medium Oil | Heavy Oil | Natural Gas | ||||||||||||||||||||||||||||||||||
Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | ||||||||||||||||||||||||||||
Company | Gross | Net | Company | Gross | Net | Company | Gross | Net | ||||||||||||||||||||||||||||
Interest | Interest | Interest | Interest | Interest | Interest | Interest | Interest | Interest | ||||||||||||||||||||||||||||
Reserves Category | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (bcf) | (bcf) | (bcf) | |||||||||||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||||||||||||||
Proved Developed Producing | 59,164 | 58,988 | 50,539 | 10,860 | 10,853 | 9,627 | 368.0 | 360.2 | 290.8 | |||||||||||||||||||||||||||
Proved Developed Non-Producing | 368 | 368 | 311 | 62 | 62 | 57 | 24.5 | 24.1 | 18.5 | |||||||||||||||||||||||||||
Proved Undeveloped | 18,761 | 18,748 | 15,574 | 1,673 | 1,673 | 1,402 | 31.2 | 29.3 | 24.2 | |||||||||||||||||||||||||||
Total Proved Reserves | 78,292 | 78,104 | 66,424 | 12,595 | 12,588 | 11,086 | 423.7 | 413.6 | 333.5 | |||||||||||||||||||||||||||
Probable Reserves | 21,361 | 21,324 | 17,820 | 3,118 | 3,117 | 2,651 | 94.4 | 91.1 | 72.7 | |||||||||||||||||||||||||||
Total Proved Plus Probable Reserves | 99,653 | 99,427 | 84,245 | 15,713 | 15,705 | 13,737 | 518.1 | 504.7 | 406.2 | |||||||||||||||||||||||||||
OIL AND GAS RESERVES | ||||||||||||||||||||||||
Natural Gas Liquids | Total Oil Equivalent Basis | |||||||||||||||||||||||
Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | |||||||||||||||||||
Company | Gross | Net | Company | Gross | Net | |||||||||||||||||||
Interest | Interest | Interest | Interest | Interest | Interest | |||||||||||||||||||
Reserves Category | (mbbls) | (mbbls) | (mbbls) | (mboe) | (mboe) | (mboe) | ||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||
Proved Developed Producing | 13,660 | 13,478 | 9,377 | 145,010 | 143,348 | 118,007 | ||||||||||||||||||
Proved Developed Non-Producing | 642 | 633 | 462 | 5,149 | 5,071 | 3,920 | ||||||||||||||||||
Proved Undeveloped | 1,157 | 1,106 | 821 | 26,788 | 26,419 | 21,834 | ||||||||||||||||||
Total Proved Reserves | 15,459 | 15,217 | 10,660 | 176,948 | 174,838 | 143,761 | ||||||||||||||||||
Probable Reserves | 3,631 | 3,552 | 2,604 | 43,839 | 43,180 | 35,193 | ||||||||||||||||||
Total Proved Plus Probable Reserves | 19,090 | 18,768 | 13,264 | 220,788 | 218,019 | 178,954 | ||||||||||||||||||
NET PRESENT VALUES OF FUTURE NET REVENUE | ||||||||||||||||||||
CONSTANT PRICES AND COSTS BEFORE INCOME TAXES | ||||||||||||||||||||
Reserves Category | DISCOUNTED AT (%/YEAR) | |||||||||||||||||||
0% ($MM) | 5% ($MM) | 10% ($MM) | 15% ($MM) | 20% ($MM) | ||||||||||||||||
Proved Reserves | ||||||||||||||||||||
Proved Developed Producing | 4,745.1 | 3,568.7 | 2,896.0 | 2,460.1 | 2,153.1 | |||||||||||||||
Proved Developed Non-Producing | 183.2 | 134.0 | 106.0 | 87.7 | 74.8 | |||||||||||||||
Proved Undeveloped | 770.4 | 499.3 | 342.5 | 243.7 | 177.4 | |||||||||||||||
Total Proved Reserves | 5,698.7 | 4,202.0 | 3,344.5 | 2,791.5 | 2,405.3 | |||||||||||||||
Probable Reserves | 1,587.6 | 904.8 | 608.7 | 449.6 | 351.6 | |||||||||||||||
Total Proved Plus Probable Reserves | 7,286.3 | 5,106.8 | 3,953.2 | 3,241.1 | 2,756.9 | |||||||||||||||
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FUTURE NET | ||||||||||||||||||||||||
CAPITAL | REVENUE | |||||||||||||||||||||||
OPERATING | DEVELOPMENT | ABANDONMENT | BEFORE | |||||||||||||||||||||
REVENUE | ROYALTIES | COSTS | COSTS | COSTS(1) | INCOME TAX | |||||||||||||||||||
Reserves Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ||||||||||||||||||
Proved Reserves | 10,453 | 1,988 | 2,348 | 318 | 99 | 5,699 | ||||||||||||||||||
Total Proved Plus Probable Reserves | 13,082 | 2,523 | 2,791 | 379 | 101 | 7,286 |
1. | Includes downhole abandonment cost but does not include surface reclamation costs. See page 37 Abandonment & Reclamation Costs. |
FUTURE NET REVENUE | ||||||
PRODUCTION GROUP | BEFORE INCOME TAXES | |||||
Reserves Category | (discounted at 10% yr) ($M) | |||||
Proved Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 1,666,575 | ||||
Heavy Oil (including solution gas and other by-products)(1) | 122,962 | |||||
Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 1,554,956 | |||||
Total Proved Plus Probable Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 1,977,086 | ||||
Heavy Oil (including solution gas and other by-products)(1) | 148,256 | |||||
Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 1,827,831 |
1. | NGL’s associated with the production of solution gas are included as a by-product. | |
2. | NGL’s associated with the production of natural gas are included as a by-product. |
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OIL AND GAS RESERVES | ||||||||||||||||||||||||||||||||||||
Light and Medium Oil | Heavy Oil | Natural Gas | ||||||||||||||||||||||||||||||||||
Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | ||||||||||||||||||||||||||||
Company | Gross | Net | Company | Gross | Net | Company | Gross | Net | ||||||||||||||||||||||||||||
Interest | Interest | Interest | Interest | Interest | Interest | Interest | Interest | Interest | ||||||||||||||||||||||||||||
Reserves Category | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (bcf) | (bcf) | (bcf) | |||||||||||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||||||||||||||
Proved Developed Producing | 58,219 | 58,060 | 49,693 | 10,924 | 10,916 | 9,621 | 366.2 | 358.5 | 289.4 | |||||||||||||||||||||||||||
Proved Developed Non-Producing | 365 | 365 | 308 | 62 | 62 | 57 | 24.3 | 23.9 | 18.4 | |||||||||||||||||||||||||||
Proved Undeveloped | 18,768 | 18,755 | 15,991 | 1,699 | 1,699 | 1,420 | 30.8 | 29.0 | 23.9 | |||||||||||||||||||||||||||
Total Proved Reserves | 77,351 | 77,179 | 65,992 | 12,684 | 12,677 | 11,098 | 421.3 | 411.4 | 331.7 | |||||||||||||||||||||||||||
Probable Reserves | 21,332 | 21,296 | 17,937 | 3,106 | 3,104 | 2,616 | 94.3 | 91.0 | 72.6 | |||||||||||||||||||||||||||
Total Proved Plus Probable Reserves | 98,684 | 98,476 | 83,929 | 15,790 | 15,781 | 13,714 | 515.6 | 502.4 | 404.3 | |||||||||||||||||||||||||||
OIL AND GAS RESERVES | ||||||||||||||||||||||||
Natural Gas Liquids | Total Oil Equivalent Basis | |||||||||||||||||||||||
Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | Pengrowth | |||||||||||||||||||
Company | Gross | Net | Company | Gross | Net | |||||||||||||||||||
Interest | Interest | Interest | Interest | Interest | Interest | |||||||||||||||||||
Reserves Category | (mbbls) | (mbbls) | (mbbls) | (mboe) | (mboe) | (mboe) | ||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||
Proved Developed Producing | 13,566 | 13,385 | 9,334 | 143,741 | 142,103 | 116,877 | ||||||||||||||||||
Proved Developed Non-Producing | 637 | 628 | 460 | 5,113 | 5,035 | 3,893 | ||||||||||||||||||
Proved Undeveloped | 1,139 | 1,088 | 805 | 26,745 | 26,376 | 22,200 | ||||||||||||||||||
Total Proved Reserves | 15,342 | 15,101 | 10,600 | 175,599 | 173,513 | 142,970 | ||||||||||||||||||
Probable Reserves | 3,643 | 3,564 | 2,617 | 43,797 | 43,138 | 35,276 | ||||||||||||||||||
Total Proved Plus Probable Reserves | 18,985 | 18,665 | 13,218 | 219,396 | 216,652 | 178,246 | ||||||||||||||||||
NET PRESENT VALUES OF FUTURE NET REVENUE | ||||||||||||||||||||
FORECAST PRICES AND COSTS BEFORE INCOME TAXES | ||||||||||||||||||||
Reserves Category | discounted at (%/year) | |||||||||||||||||||
0% ($MM) | 5% ($MM) | 10% ($MM) | 15% ($MM) | 20% ($MM) | ||||||||||||||||
Proved Reserves | ||||||||||||||||||||
Proved Developed Producing | 3,676.7 | 2,871.1 | 2,401.0 | 2,089.9 | 1,865.9 | |||||||||||||||
Proved Developed Non-Producing | 148.7 | 109.2 | 87.6 | 73.7 | 63.8 | |||||||||||||||
Proved Undeveloped | 559.9 | 347.9 | 229.6 | 156.7 | 108.5 | |||||||||||||||
Total Proved Reserves | 4,385.3 | 3,328.2 | 2,718.2 | 2,320.3 | 2,038.2 | |||||||||||||||
Probable Reserves | 1,308.2 | 727.9 | 486.3 | 359.7 | 282.8 | |||||||||||||||
Total Proved Plus Probable Reserves | 5,693.5 | 4,056.1 | 3,204.5 | 2,680.0 | 2,321.0 | |||||||||||||||
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FUTURE NET | ||||||||||||||||||||||||
CAPITAL | REVENUE | |||||||||||||||||||||||
OPERATING | DEVELOPMENT | ABANDONMENT | BEFORE | |||||||||||||||||||||
REVENUE | ROYALTIES | COSTS | COSTS | COSTS(1) | INCOME TAX | |||||||||||||||||||
Reserves Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ||||||||||||||||||
Proved Reserves | 9,302 | 1,712 | 2,735 | 335 | 134 | 4,385 | ||||||||||||||||||
Total Proved Plus Probable Reserves | 11,818 | 2,186 | 3,390 | 402 | 147 | 5,694 |
1. | Includes downhole abandonment cost but does not include surface reclamation costs. See page 37 Abandonment & Reclamation Costs. |
FUTURE NET REVENUE | ||||||
PRODUCTION GROUP | BEFORE INCOME TAXES | |||||
Reserves Category | (discounted at 10% yr) ($M) | |||||
Proved Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 1,285,742 | ||||
Heavy Oil (including solution gas and other by-products)(1) | 138,224 | |||||
Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 1,294,222 | |||||
Total Proved Plus Probable Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 1,532,149 | ||||
Heavy Oil (including solution gas and other by-products)(1) | 165,396 | |||||
Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 1,506,936 |
1. | NGL’s associated with the production of solution gas are included as a by-product. | |
2. | NGL’s associated with the production of natural gas are included as a by-product. |
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EXCHANGE | ||||||||||||||||||||||||||||||||||||
OIL | NATURAL GAS | NATURAL GAS LIQUIDS(1) | RATE(2) | |||||||||||||||||||||||||||||||||
Edmonton | Cromer | LLB Crude | ||||||||||||||||||||||||||||||||||
WTI Cushing | Par Price | Medium | Oil at | AECO | ||||||||||||||||||||||||||||||||
Oklahoma | 400 API | 29.30API | Hardisty | Gas Price | Propane | Butane | Pentanes Plus | |||||||||||||||||||||||||||||
YEAR(3) | ($US/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/mmbtu) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($US/Cdn) | |||||||||||||||||||||||||||
2005(4) | 61.04 | 68.27 | 51.84 | 39.20 | 9.71 | 43.69 | 50.52 | 71.67 | 0.8577 |
1. | FOB Edmonton. | |
2. | The exchange rate used to generate the benchmark reference prices in this table. | |
3. | Information provided as at December 31, 2005. | |
4. | This forecast represents the constant price forecast used by GLJ and is a representation of posted prices as of December 31, 2005. |
INFLATION | EXCHANGE | |||||||||||||||||||||||||||||||||||||||
OIL | NATURAL GAS | NATURAL GAS LIQUIDS(1) | RATES(2) | RATE(3) | ||||||||||||||||||||||||||||||||||||
Edmonton Par | Cromer | Hardisty | ||||||||||||||||||||||||||||||||||||||
WTI Cushing | Price | Medium | Heavy | AECO | ||||||||||||||||||||||||||||||||||||
Oklahoma | 400API | 29.30API | 120API | Gas Price | Propane | Butane | Pentanes Plus | |||||||||||||||||||||||||||||||||
Year | ($US/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/mmbtu) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | (%/Year) | ($US/Cdn) | ||||||||||||||||||||||||||||||
2005(4) | 56.60 | 69.11 | 57.07 | 34.14 | 8.58 | 42.55 | 51.41 | 69.45 | 2.20 | % | 0.825 | |||||||||||||||||||||||||||||
2006 | 57.00 | 66.25 | 55.75 | 33.25 | 10.60 | 42.50 | 49.00 | 67.00 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2007 | 55.00 | 64.00 | 55.25 | 32.75 | 9.25 | 41.00 | 47.25 | 65.25 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2008 | 51.00 | 59.25 | 51.25 | 32.50 | 8.00 | 38.00 | 43.75 | 60.50 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2009 | 48.00 | 55.75 | 48.25 | 32.50 | 7.50 | 35.75 | 41.25 | 56.75 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2010 | 46.50 | 54.00 | 46.75 | 32.00 | 7.20 | 34.50 | 40.00 | 55.00 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2011 | 45.00 | 52.25 | 45.25 | 33.50 | 6.90 | 33.50 | 38.75 | 53.25 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2012 | 45.00 | 52.25 | 45.25 | 33.50 | 6.90 | 33.50 | 38.75 | 53.25 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2013 | 46.00 | 53.25 | 46.00 | 34.00 | 7.05 | 34.00 | 39.50 | 54.25 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2014 | 46.75 | 54.25 | 47.00 | 34.75 | 7.20 | 34.75 | 40.25 | 55.25 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2015 | 47.75 | 55.50 | 48.00 | 35.25 | 7.40 | 35.50 | 41.00 | 56.50 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
2016 | 48.75 | 56.50 | 48.75 | 36.00 | 7.55 | 36.25 | 41.75 | 57.75 | 2.00 | % | 0.850 | |||||||||||||||||||||||||||||
Thereafter | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | 2.00 | % | 0.850 |
1. | FOB Edmonton. | |
2. | Inflation rates for forecasting prices and costs. | |
3. | The exchange rates used to generate the benchmark reference prices in this table. | |
4. | Actual average prices, inflation rate and exchange rate estimated for 2005. |
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LIGHT AND MEDIUM OIL | NATURAL GAS | NATURAL GAS LIQUIDS | ||||||||||||||||||||||||||||||||||
Net | Net | Net | ||||||||||||||||||||||||||||||||||
Proved | Proved | Proved | ||||||||||||||||||||||||||||||||||
Net | Net | Plus | Net | Net | Plus | Net | Net | Plus | ||||||||||||||||||||||||||||
Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||||||||||||
Factors | (mbbls) | (mbbls) | (mbbls) | (bcf) | (bcf) | (bcf) | (mbbls) | (mbbls) | (mbbls) | |||||||||||||||||||||||||||
December 31, 2004 | 63,572 | 16,871 | 80,443 | 341.4 | 74.0 | 415.4 | 10,974 | 2,845 | 13,819 | |||||||||||||||||||||||||||
Extensions | — | — | — | 13.9 | 2.7 | 16.6 | 492 | 78 | 570 | |||||||||||||||||||||||||||
Improved Recovery | 1,986 | 225 | 2,211 | 1.3 | 0.2 | 1.5 | 309 | (116 | ) | 193 | ||||||||||||||||||||||||||
Technical Revisions | (354 | ) | (1,107 | ) | (1,461 | ) | 10.6 | (9.6 | ) | 1.0 | 591 | (259 | ) | 332 | ||||||||||||||||||||||
Discoveries | — | — | — | 1.7 | 0.4 | 2.1 | 2 | 1 | 3 | |||||||||||||||||||||||||||
Acquisitions | 7,769 | 2,183 | 9,952 | 15.2 | 6.1 | 21.3 | 260 | 73 | 333 | |||||||||||||||||||||||||||
Dispositions | (1,174 | ) | (235 | ) | (1,409 | ) | (3.9 | ) | (1.1 | ) | (5.0 | ) | (71 | ) | (4 | ) | (75 | ) | ||||||||||||||||||
Economic Factors | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Production | (5,807 | ) | — | (5,807 | ) | (48.6 | ) | — | (48.6 | ) | (1,957 | ) | — | (1,957 | ) | |||||||||||||||||||||
December 31, 2005 | 65,992 | 17,937 | 83,929 | 331.6 | 72.7 | 404.3 | 10,600 | 2,618 | 13,218 | |||||||||||||||||||||||||||
HEAVY OIL | TOTAL OIL EQUIVALENT BASIS | |||||||||||||||||||||||
Net | Net | |||||||||||||||||||||||
Proved | Proved | |||||||||||||||||||||||
Net | Net | Plus | Net | Net | Plus | |||||||||||||||||||
Proved | Probable | Probable | Proved | Probable | Probable | |||||||||||||||||||
Factors | (mbbls) | (mbbls) | (mbbls) | (mboe) | (mboe) | (mboe) | ||||||||||||||||||
December 31, 2004 | 12,733 | 3,065 | 15,798 | 144,171 | 35,114 | 179,298 | ||||||||||||||||||
Extensions | — | — | — | 2,815 | 526 | 3,341 | ||||||||||||||||||
Improved Recovery | 117 | 12 | 129 | 2,635 | 146 | 2,781 | ||||||||||||||||||
Technical Revisions | 59 | (471 | ) | (412 | ) | 2,074 | (3,435 | ) | (1,370 | ) | ||||||||||||||
Discoveries | 71 | 9 | 80 | 348 | 87 | 435 | ||||||||||||||||||
Acquisitions | — | — | — | 10,561 | 3,266 | 13,827 | ||||||||||||||||||
Dispositions | — | — | — | (1,888 | ) | (432 | ) | (2,320 | ) | |||||||||||||||
Economic Factors | — | — | — | — | — | — | ||||||||||||||||||
Production | (1,882 | ) | — | (1,882 | ) | (17,746 | ) | — | (17,746 | ) | ||||||||||||||
December 31, 2005 | 11,098 | 2,615 | 13,714 | 142,970 | 35,272 | 178,246 | ||||||||||||||||||
- 30 -
Proved | ||||||||||||
Proved | Total | Plus | ||||||||||
Producing | Proved | Probable | ||||||||||
Reserves | Reserves | Reserves | ||||||||||
(mboe) | (mboe) | (mboe) | ||||||||||
December 31, 2004 | 142,353 | 175,502 | 218,613 | |||||||||
Exploration and Development | 2,797 | 4,096 | 4,898 | |||||||||
Improved Recovery and Infill Drilling | 7,386 | 3,193 | 3,342 | |||||||||
Revisions | 6,105 | 4,072 | 344 | |||||||||
Acquisitions | 8,964 | 12,699 | 16,697 | |||||||||
Dispositions | (2,197 | ) | (2,296 | ) | (2,831 | ) | ||||||
Production | (21,667 | ) | (21,667 | ) | (21,667 | ) | ||||||
December 31, 2005 | 143,741 | 175,599 | 219,396 | |||||||||
• | The acquisition of Crispin and additional interest in Swan Hills Unit No. 1 accounted for 66 percent of the Total Proved Plus Probable Reserves added in 2005. | ||
• | New reserves were added from development activity, mainly at Weyburn for infill drilling and improved recovery, West Pembina for drilling extensions and Gutah, in northeast British Columbia where reserves for the field could be booked when economics became favorable. Reserve increases in the Proved Producing category also resulted from reclassification of Proved Undeveloped reserves primarily for development drilling in the SOEP South Venture field and infill drilling in the Dunvegan Unit and Princess shallow gas properties. | ||
• | Various performance related revisions were made to previous estimates resulting in a net positive change. The largest revisions to proved reserves occurred at Weyburn (+1,131 mboe), Twining (+912 mboe), McLeod River (+484 mboe), Quirk Creek (+464 mboe), SOEP (+464 mboe), Monogram (+461 mboe), Nipisi (+458 mboe), Swan Hills Unit No. 1 (-958 mboe), and Squirrel (-455 mboe). | ||
• | Numerous small, non-core properties were sold in a disposition program which concluded late in 2005. |
- 31 -
CONSTANT PRICES AND COSTS
PERIOD AND FACTOR | Before Tax 2005 ($M) | |||
Estimated Net Present Value at Beginning of Year | 1,992,385 | |||
Oil and Gas Sales During the Period Net of Production Costs and Royalties(1) | (706,339 | ) | ||
Net Change due to Prices and Royalties Related to Forecast Production(2) | 1,450,352 | |||
Change in Development Costs During the Period(3) | 165,800 | |||
Change in Forecast Development Costs(4) | (139,485 | ) | ||
Change Resulting from Extensions, Infill Drilling and Improved Recovery(5) | 126,767 | |||
Net Change Resulting from Discoveries(5) | 8,094 | |||
Change Resulting from Acquisitions of Reserves(5) | 195,907 | |||
Change Resulting from Dispositions of Reserves(6) | (26,035 | ) | ||
Accretion of Discount(7) | 199,239 | |||
Net Change in Income Taxes(8) | — | |||
Change Resulting from Technical Reserves Revisions(5) | 48,218 | |||
All Other Changes | 29,592 | |||
Estimated Net Present Value at End of Year | 3,344,494 | |||
1. | 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 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. | Start of period net present value of related reserves. | |
7. | Estimated as 10 percent of the beginning of period net present value. | |
8. | 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. |
- 32 -
2006(1) | 2007(1) | 2008(1) | 2009(1) | 2010(1) | Remainder(1) | Total(1) | Total(2) | |||||||||||||||||||||||||
Reserve Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ||||||||||||||||||||||||
Proved Reserves (Constant Prices and Costs) | 109.5 | 62.4 | 40.2 | 23.4 | 14.0 | 68.9 | 318.4 | 246.4 | ||||||||||||||||||||||||
Proved Reserves (Forecast Prices and Costs) | 109.5 | 63.6 | 41.9 | 24.9 | 15.2 | 80.3 | 335.4 | 255.0 | ||||||||||||||||||||||||
Proved & Probable Reserves (Forecast Prices and Costs) | 121.1 | 75.3 | 52.0 | 29.9 | 20.1 | 103.4 | 401.8 | 300.2 |
1. | Undiscounted. | |
2. | Discounted at 10 percent. |
- 33 -
- 34 -
Proved plus | ||||||||
Proved | Probable | |||||||
FD&A Costs Excluding Future Development Capital | ||||||||
Exploration and Development Capital Expenditures — $thousands | $ | 175,700 | $ | 175,700 | ||||
Exploration and Development Reserve Additions including Revisions — mboe | 11,361 | 8,591 | ||||||
Finding and Development Cost — $/boe | $ | 15.47 | $ | 20.45 | ||||
Net Acquisition Capital — $thousands | $ | 175,100 | $ | 175,100 | ||||
Net Acquisition Reserve Additions — mboe | 10,403 | 13,866 | ||||||
Net Acquisition Cost — $/boe | $ | 16.83 | $ | 12.63 | ||||
Total Capital Expenditures including Net Acquisitions — $thousands | $ | 350,800 | $ | 350,800 | ||||
Reserve Additions including Net Acquisitions — mboe | 21,764 | 22,457 | ||||||
Finding Development and Acquisition Cost — $/boe | $ | 16.12 | $ | 15.62 | ||||
FD&A Costs Including Future Development Capital | ||||||||
Exploration and Development Capital Expenditures — $thousands | $ | 175,700 | $ | 175,700 | ||||
Exploration and Development Change in FDC — $thousands | ($ | 54,931 | ) | ($ | 50,749 | ) | ||
Exploration and Development Capital including Change in FDC — $thousands | $ | 120,769 | $ | 124,951 | ||||
Exploration and Development Reserve Additions including Revisions — mboe | 11,361 | 8,591 | ||||||
Finding and Development Cost — $/boe | $ | 10.63 | $ | 14.54 | ||||
Net Acquisition Capital — $thousands | $ | 175,100 | $ | 175,100 | ||||
Net Acquisition FDC — $thousands | $ | 17,900 | $ | 24,700 | ||||
Net Acquisition Capital including FDC — $thousands | $ | 193,000 | $ | 199,800 | ||||
Net Acquisition Reserve Additions — mboe | 10,403 | 13,866 | ||||||
Net Acquisition Cost — $/boe | $ | 18.55 | $ | 14.41 | ||||
Total Capital Expenditures including Net Acquisitions — $thousands | $ | 350,800 | $ | 350,800 | ||||
Total Change in FDC — $thousands | ($ | 37,031 | ) | ($ | 26,049 | ) | ||
Total Capital including Change in FDC — $thousands | $ | 313,769 | $ | 324,751 | ||||
Reserve Additions including Net Acquisitions — mboe | 21,764 | 22,457 | ||||||
Finding Development and Acquisition Cost including FDC — $/boe | $ | 14.42 | $ | 14.46 | ||||
- 35 -
PRODUCING | NON-PRODUCING | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Crude Oil Wells | ||||||||||||||||
Alberta | 1,293 | 613 | 408 | 245 | ||||||||||||
British Columbia | 151 | 106 | 48 | 44 | ||||||||||||
Saskatchewan | 1,078 | 283 | 193 | 84 | ||||||||||||
Nova Scotia | 0 | 0 | 0 | 0 | ||||||||||||
Natural Gas Wells | ||||||||||||||||
Alberta | 2,794 | 943 | 176 | 48 | ||||||||||||
British Columbia | 146 | 81 | 65 | 51 | ||||||||||||
Saskatchewan | 40 | 31 | 83 | 43 | ||||||||||||
Nova Scotia | 18 | 1 | 0 | 0 | ||||||||||||
Other | ||||||||||||||||
Alberta(1) | 50 | 42 | 142 | 103 | ||||||||||||
British Columbia(1) | 0 | 0 | 50 | 46 | ||||||||||||
Saskatchewan(1) | 21 | 15 | 22 | 19 | ||||||||||||
Total | 5,591 | 2,115 | 1,187 | 683 | ||||||||||||
1. | We cannot classify these wells as either oil or gas. |
UNPROVED PROPERTIES (acres) | ||||||||||||
Location | Gross | Net | Net Area to Expire(1) | |||||||||
Alberta | 331,085 | 198,471 | 21,013 | |||||||||
British Columbia | 301,302 | 139,365 | 17,007 | |||||||||
Saskatchewan | 55,955 | 44,808 | 1,160 | |||||||||
Nova Scotia | 0 | 0 | 0 | |||||||||
Other | 0 | 0 | 0 | |||||||||
TOTAL | 688,342 | 382,644 | 39,180 | |||||||||
1. | This acreage will expire if we take no action to continue the term through operational or administrative actions. Taking these actions may or may not cause the land expiry to be stayed. |
- 36 -
2006 | 2007 | 2008 | Remainder | Total | ||||||||||||||||
($M) | ($M) | ($M) | ($M) | ($M) | ||||||||||||||||
Total Abandonment, Reclamation, Remediation & Dismantling | 14,866 | 15,888 | 14,154 | 995,985 | 1,040,893 | |||||||||||||||
Discounted at 10% | 14,174 | 13,772 | 11,154 | 107,408 | 146,508 |
- 37 -
NATURE OF COST | AMOUNT ($MM) | |||
Acquisition Costs | ||||
Proved | 208.4 | |||
Unproved | 18.7 | |||
Exploration Costs | 0.0 | |||
Development Costs | 204.0 | |||
Total | 431.1 | |||
GROSS | NET | |||||||
Development Wells | ||||||||
Gas | 209 | 73.7 | ||||||
Oil | 70 | 15.4 | ||||||
Service | 3 | 2.1 | ||||||
Dry | 4 | 2.7 | ||||||
Total Wells | 286 | 93.9 | ||||||
PRODUCTION | ||||||||
Total Proved Constant | Proved Plus Probable Forecast | |||||||
Prices and Costs | Prices and Costs | |||||||
Light and Medium Crude Oil (bblpd) | 19,799 | 20,420 | ||||||
Heavy Oil (bblpd) | 4,892 | 5,169 | ||||||
Natural Gas (mcfpd) | 153,257 | 156,194 | ||||||
Natural Gas Liquids (bblpd) | 5,489 | 5,613 | ||||||
Oil Equivalent (boepd) | 55,723 | 57,234 |
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QUARTER ENDED | ||||||||||||||||
March 31, | June 30, | September 30, | December 31, | |||||||||||||
2005 | 2005 | 2005 | 2005 | |||||||||||||
Light Crude Oil | ||||||||||||||||
Average Daily Oil Production(1) (bblpd) | 20,443 | 20,906 | 20,660 | 21,179 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/bbl) | 54.42 | 56.44 | 63.95 | 59.40 | ||||||||||||
Processing and other income ($/bbl) | 0.80 | 1.03 | 1.01 | 0.51 | ||||||||||||
Royalties ($/bbl) | (7.11 | ) | (9.96 | ) | (11.03 | ) | (6.47 | ) | ||||||||
Amortization of injectants ($/bbl) | (2.93 | ) | (3.13 | ) | (3.14 | ) | (3.63 | ) | ||||||||
Production Costs(2)($/bbl) | (11.04 | ) | (11.44 | ) | (13.14 | ) | (14.59 | ) | ||||||||
Operating Netback ($/bbl) | 34.14 | 32.94 | 37.65 | 35.22 | ||||||||||||
Heavy Oil | ||||||||||||||||
Average Daily Oil Production(1) (bblpd) | 6,046 | 5,641 | 5,405 | 5,410 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/bbl) | 24.39 | 30.32 | 47.74 | 31.77 | ||||||||||||
Processing and other income ($/bbl) | 0.99 | 0.49 | (0.83 | ) | 0.74 | |||||||||||
Royalties ($/bbl) | (2.58 | ) | (4.75 | ) | (8.00 | ) | (2.98 | ) | ||||||||
Production Costs(2)($/bbl) | (18.56 | ) | (15.88 | ) | (16.30 | ) | (11.60 | ) | ||||||||
Operating Netback ($/bbl) | 4.24 | 10.18 | 22.61 | 17.93 | ||||||||||||
NGLs | ||||||||||||||||
Average Daily NGL Production(1) (bblpd) | 6,345 | 5,870 | 5,448 | 6,710 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/bbl) | 50.48 | 50.03 | 57.75 | 58.46 | ||||||||||||
Royalties ($/bbl) | (14.07 | ) | (14.59 | ) | (20.57 | ) | (21.29 | ) | ||||||||
Production Costs(2)($/bbl) | (6.88 | ) | (9.15 | ) | (10.13 | ) | (10.05 | ) | ||||||||
Operating Netback ($/bbl) | 29.53 | 26.29 | 27.05 | 27.12 | ||||||||||||
Natural Gas | ||||||||||||||||
Average Daily Gas Production(1) (mcfpd) | 157,491 | 153,423 | 164,288 | 168,862 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/mcf) | 6.84 | 7.34 | 8.57 | 11.97 | ||||||||||||
Processing and other income ($/mcf) | 0.21 | 0.44 | 0.09 | 0.19 | ||||||||||||
Royalties ($/mcf) | (1.27 | ) | (1.34 | ) | (1.47 | ) | (2.62 | ) | ||||||||
Production Costs(2)($/mcf) | (1.17 | ) | (1.25 | ) | (1.40 | ) | (1.50 | ) | ||||||||
Operating Netback ($/mcf) | 4.61 | 5.19 | 5.79 | 8.04 |
QUARTER ENDED | ||||||||||||||||
March 31, | June 30, | September 30, | December 31, | |||||||||||||
2005 | 2005 | 2005 | 2005 | |||||||||||||
Barrels of Oil Equivalent | ||||||||||||||||
Average Daily Production(1) (boepd) | 59,082 | 57,988 | 58,894 | 61,442 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/boe) | 44.97 | 47.79 | 56.07 | 62.55 | ||||||||||||
Processing and other income ($/boe) | 0.94 | 1.58 | 0.52 | 0.77 | ||||||||||||
Royalties ($/boe) | (7.63 | ) | (9.08 | ) | (10.60 | ) | (12.02 | ) | ||||||||
Amortization of injectants ($/boe) | (1.01 | ) | (1.13 | ) | (1.10 | ) | (1.25 | ) | ||||||||
Production Costs(2) ($/boe) | (9.57 | ) | (9.90 | ) | (10.95 | ) | (11.24 | ) | ||||||||
Operating Netback ($/boe) | 27.70 | 29.26 | 33.94 | 38.81 |
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Light/Medium Oil | Heavy Oil | Natural Gas | Natural Gas Liquids | |||||||||||||||||||||||||||||||||
Average | Average | Average | Average | Average | ||||||||||||||||||||||||||||||||
Annual | Daily | Annual | Daily | Annual | Daily | Annual | Daily | Daily Total | ||||||||||||||||||||||||||||
Production | Production | Production | Production | Production | Production | Production | Production | Production | ||||||||||||||||||||||||||||
Year Ended | (mbbls) | (bblpd) | (mbbls) | (bblpd) | (mmcf) | (mcfpd) | (mbbls) | (bblpd) | (boepd) | |||||||||||||||||||||||||||
Dec 31, 1997 | 2,792 | 7,650 | — | — | 18,744 | 51,355 | 677 | 1,856 | 18,140 | |||||||||||||||||||||||||||
Dec 31, 1998 | 6,094 | 16,695 | — | — | 21,063 | 57,707 | 1,220 | 3,342 | 29,741 | |||||||||||||||||||||||||||
Dec 31, 1999 | 6,413 | 17,570 | — | — | 22,445 | 61,494 | 1,433 | 3,927 | 31,821 | |||||||||||||||||||||||||||
Dec 31, 2000 | 6,441 | 17,599 | — | — | 25,656 | 70,098 | 1,539 | 4,205 | 33,581 | |||||||||||||||||||||||||||
Dec 31, 2001 | 7,200 | 19,726 | — | — | 33,494 | 91,764 | 1,919 | 5,258 | 40,320 | |||||||||||||||||||||||||||
Dec 31, 2002 | 7,269 | 19,914 | — | — | 40,775 | 111,713 | 1,917 | 5,252 | 43,785 | |||||||||||||||||||||||||||
Dec 31, 2003 | 8,518 | 23,337 | — | — | 43,742 | 119,842 | 2,089 | 5,722 | 49,033 | |||||||||||||||||||||||||||
Dec 31, 2004 | 7,619 | 20,817 | 1,302 | 3,558 | 52,806 | 144,278 | 1,933 | 5,281 | 53,702 | |||||||||||||||||||||||||||
Dec 31, 2005 | 7,591 | 20,799 | 2,052 | 5,623 | 58,786 | 161,056 | 2,224 | 6,093 | 59,357 |
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a. | a vote may be held only if requested in writing by the holders of not less than 25 percent of the Trust Units, or if the Trust Units have become ineligible for investment by RRSPs, RRIFs, RESPs and DPSPs; | ||
b. | the termination must be approved by extraordinary resolution of the Unitholders; and | ||
c. | a quorum representing five percent of the issued and outstanding Trust Units must be present or represented by proxy at the meeting at which the vote is taken. |
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Class A Trust Units |
• | are not subject to any residency restriction; | ||
• | are subject to a restriction on the number to be issued such that the total number of issued and outstanding Class A Trust Units will not exceed 99% of the number of issued and outstanding Class B Trust Units (after an initial implementation period) (the “Ownership Threshold”); |
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• | may be converted by a holder at any time into Class B Trust Units provided that the holder is a resident of Canada and provides a suitable residency declaration; | ||
• | trade on both the TSX and NYSE; and | ||
• | have identical rights to voting, distributions and assets of Pengrowth Trust on a wind-up to the Class B Trust Units. |
Class B Trust Units |
• | may not be owned or controlled, directly or indirectly, otherwise than by security only, by non-residents of Canada; | ||
• | trade only on the TSX; | ||
• | may be converted by a holder into Class A Trust Units, provided that the Ownership Threshold will not be exceeded (see page 11 “General Development of Pengrowth Trust - Recent Acquisitions, Financings and Developments — Conversion of Class B Trust Units into Class A Trust Units”); and | ||
• | have identical rights to voting, distributions and assets of Pengrowth Trust on a wind-up to the Class A Trust Units. |
• | The Canadian Depository for Securities Limited (“CDS”) has been 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”) is not be permitted to hold Class B Trust Units; | ||
• | a residency declaration is required for any proposed registered transfer of Class B Trust Units; and | ||
• | a residency declaration is required for any proposed conversion of Class A Trust Units into Class B Trust Units. |
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• | holders of Class A Trust Units do not have the right to convert Class A Trust Units to Class B Trust Units where an exclusionary offer is made for the Class B Trust Units if the offeror is a non-resident of Canada (this would not be a valid offer because a non-resident is not permitted to hold Class B Trust Units); | ||
• | where Class B Trust Units are converted to Class A Trust Units upon an exclusionary offer being made for the Class A Trust Units, those units will be immediately converted back to Class B Trust 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 (even if the offeror is a non-resident of Canada and Pengrowth will have all of the remedies described above against such offeror); | ||
• | if a non-resident acquires 10 percent or more of the outstanding Class A Trust Units (including Class A Trust Units issued on the conversion of Class B Trust 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 Trust Units; | ||
• | if Class A Trust Units or Class B Trust Units are tendered to an exclusionary offer for the Class B Trust Units or the Class A Trust 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 | ||
• | if an exclusionary offer is withdrawn or expires, or Trust Units that are tendered to an exclusionary offer are withdrawn, no conversion will occur. |
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a. | operating costs; | ||
b. | general and administrative costs; | ||
c. | management fees and debt service charges; | ||
d. | taxes or other charges payable by the Corporation; and | ||
e. | any amounts paid into the “reserve”. |
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(Canadian $)
2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
First Quarter | 0.69 | 0.63 | 0.75 | 0.41 | 1.14 | |||||||||||||||
Second Quarter | 0.69 | 0.64 | 0.67 | 0.54 | 0.83 | |||||||||||||||
Third Quarter | 0.69 | 0.67 | 0.63 | 0.52 | 0.63 | |||||||||||||||
Fourth Quarter | 0.75 | 0.69 | 0.63 | 0.60 | 0.41 |
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Toronto Stock Exchange | New York Stock Exchange | |||||||||||||||||||||||||||||||
Share Price Range | Share Price Range | |||||||||||||||||||||||||||||||
High | Low | Close | Volume | High | Low | Close | Volume | |||||||||||||||||||||||||
(Canadian $ per trust unit) | (thousands) | (U.S. $ per trust unit) | (thousands) | |||||||||||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||||||
January | 26.51 | 23.18 | 25.76 | 484 | 21.44 | 19.10 | 20.75 | 6,259 | ||||||||||||||||||||||||
February | 28.29 | 25.75 | 26.75 | 962 | 22.94 | 20.75 | 21.56 | 7,330 | ||||||||||||||||||||||||
March | 26.80 | 22.15 | 24.03 | 603 | 21.56 | 18.11 | 20.00 | 11,032 | ||||||||||||||||||||||||
April | 26.01 | 23.95 | 25.30 | 684 | 20.95 | 19.20 | 20.17 | 6,511 | ||||||||||||||||||||||||
May | 26.39 | 24.23 | 25.89 | 422 | 20.79 | 19.05 | 20.61 | 4,307 | ||||||||||||||||||||||||
June | 27.90 | 25.75 | 27.20 | 692 | 22.74 | 20.62 | 22.25 | 5,335 | ||||||||||||||||||||||||
July | 28.98 | 26.84 | 28.55 | 634 | 23.45 | 22.00 | 23.40 | 4,265 | ||||||||||||||||||||||||
August | 29.39 | 26.30 | 28.39 | 593 | 24.20 | 21.55 | 23.93 | 6,025 | ||||||||||||||||||||||||
September | 30.10 | 27.38 | 29.50 | 820 | 25.75 | 23.05 | 25.42 | 4,212 | ||||||||||||||||||||||||
October | 29.80 | 23.64 | 25.58 | 687 | 25.56 | 20.00 | 21.75 | 8,554 | ||||||||||||||||||||||||
November | 27.85 | 24.61 | 26.65 | 427 | 23.74 | 20.75 | 22.84 | 5,448 | ||||||||||||||||||||||||
December | 28.35 | 26.51 | 27.41 | 211 | 24.35 | 22.95 | 23.53 | 3,807 |
Toronto Stock Exchange | ||||||||||||||||
Share Price Range | ||||||||||||||||
High | Low | Close | Volume | |||||||||||||
(Canadian $ per trust unit ) | (thousands) | |||||||||||||||
2005 | ||||||||||||||||
January | 19.25 | 18.24 | 18.95 | 7,574 | ||||||||||||
February | 19.90 | 18.79 | 18.88 | 10,415 | ||||||||||||
March | 18.80 | 16.10 | 17.05 | 11,230 | ||||||||||||
April | 18.08 | 16.37 | 17.24 | 6,682 | ||||||||||||
May | 17.98 | 16.80 | 17.50 | 6,121 | ||||||||||||
June | 19.01 | 17.41 | 18.40 | 6,566 | ||||||||||||
July | 18.50 | 18.95 | 18.50 | 7,747 | ||||||||||||
August | 19.47 | 18.25 | 19.45 | 7,523 | ||||||||||||
September | 21.26 | 19.28 | 20.58 | 7,467 | ||||||||||||
October | 20.83 | 17.27 | 18.50 | 5,651 | ||||||||||||
November | 21.75 | 18.34 | 21.35 | 6,032 | ||||||||||||
Decem ber | 23.38 | 20.87 | 22.65 | 8,064 |
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Name and Municipality of Residence | Position with Pengrowth Management | Principal Occupation | ||
James S. Kinnear Calgary, Alberta | President and Director (since 1982) | President, Pengrowth Management Limited | ||
Gordon M. Anderson Calgary, Alberta | Vice President, Financial Services (since 2001) Vice President, Treasurer (1998-2001) Treasurer (1995-1998) | Vice President, Financial Services Pengrowth Management Limited | ||
Charles V. Selby Calgary, Alberta | Corporate Secretary (since 1993) | Lawyer, Selby Professional Corporation Lawyer and Corporate Financial Advisor |
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Trust Units | ||||||||
Controlled or | ||||||||
Name and Municipality of | Beneficially | |||||||
Residence | Position with Pengrowth Corporation | Principal Occupation | Owned(1)(2) | |||||
James S. Kinnear(7) Calgary, Alberta | President, Chairman, Director and Chief Executive Office (since 1988) | President, Pengrowth Management Limited | 4,051,039 | |||||
Stanley H. Wong(4)(8) Calgary, Alberta | Director (since 1988) | President, Carbine Resources Ltd. a private oil and gas producing and engineering consulting company | 46,576 | |||||
John B. Zaozirny(5)(6) Calgary, Alberta | Director (since 1988) | Counsel, McCarthy Tétrault, Barristers and Solicitors | 47,362 | |||||
Thomas A. Cumming(3)(5)(6) Calgary, Alberta | Director (since 2000) | Business Consultant | 6,678 | |||||
Michael S. Parrett(3)(5)(6) Aurora, Ontario | Director (since 2004) | Business Consultant | 4,000 | |||||
Kirby L. Hedrick(3)(4) Pinedale, Wyoming | Director (since 2005) | Business Consultant | Nil | |||||
A. Terence Poole(3)(5) Calgary, Alberta | Director (since 2005) | Executive Vice President, Corporate Strategy and Development, Nova Chemicals Corporation | 10,000 | |||||
Gordon M. Anderson Calgary, Alberta | Vice President (since 2001) Vice President, Treasurer (1997-2001) Treasurer (1995-1997) Chief Financial Officer (1991-1998) | Vice President, Financial Services, Pengrowth Management Limited | 47,245 | |||||
Charles V. Selby Calgary, Alberta | Vice President and Corporate Secretary (since 2005) Corporate Secretary (since 1993) | Lawyer, Selby Professional Corporation Lawyer and Corporate Financial Advisor | 127,970 | |||||
Chris Webster Calgary, Alberta | Chief Financial Officer (since 2005) Treasurer (2000 — 2005) | Chief Financial Officer Pengrowth Corporation | 19,348 | |||||
Larry B. Strong Bragg Creek, Alberta | Vice President, Geosciences (since 2005) | Vice President, Geosciences Pengrowth Corporation | 16,357 | |||||
William G. Christensen Calgary, Alberta | Vice President, Strategic Planning and Reservoir Exploitation (since 2005) | Vice President, Strategic Planning and Reservoir Exploitation Pengrowth Corporation | 5,589 | |||||
James E.A. Causgrove Calgary, Alberta | Vice President, Production and Operations (since 2005) | Vice President, Production and Operations Pengrowth Corporation | 11,330 | |||||
Douglas C. Bowles Calgary, Alberta | Vice President and Controller (since March 1, 2006) Controller (since 2005) | Vice President and Controller Pengrowth Corporation | 3,834 | |||||
Peter Cheung Calgary, Alberta | Treasurer (since 2005) | Treasurer Pengrowth Corporation | 4,653 |
1. | Does not include Class B Trust Units issuable upon the exercise of outstanding Trust Unit options, Trust Unit rights or deferred entitlement units. | |
2. | As at March 7, 2006. | |
3. | Member of Audit Committee. | |
4. | Member of Reserves Committee. | |
5. | Member of Corporate Governance Committee. | |
6. | Member of the Compensation Committee. | |
7. | In addition, Mr. Kinnear exercises control over 13,152 royalty units which are held by Pengrowth Management Limited. | |
8. | In addition, Mr. Wong exercises control over 3,288 royalty units held by Carbine Resources Ltd. |
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(i) | was the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under securities legislation for a period of more than 30 consecutive days; or |
(ii) | was subject to an event that resulted, after the person ceased to be a director or executive officer, in the issuer being the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under securities legislation for a period of more than 30 consecutive days; or |
(iii) | within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets. |
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(i) | been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, other than: (a) penalties for late filing of insider reports; and (b) Mr. Selby, the Corporate Secretary of the Corporation, and other directors of AltaCanada Energy Corp. entered into a settlement agreement in 1998 with the Alberta Securities Commission in regard to the application of rules governing junior capital pool companies to drilling expenses assumed by the directors on behalf of the Company; or |
(ii) | been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision. |
Financially | ||||||
Name | Independent | Literate | Relevant Education and Experience | |||
Thomas A. Cumming | Yes | Yes | Mr. Cumming was President and Chief Executive Officer of the Alberta Stock Exchange from 1988 to 1999. His career also includes 25 years with a major Canadian bank both nationally and internationally. He is currently Chairman of Alberta’s Electricity Balancing Pool, and serves as a Director of the Canadian Investor Protection Fund, the Alberta Capital Market Foundation and Western Lakota Energy Services Inc. Mr. Cumming is a professional engineer and holds a Bachelor of Applied Science degree in Engineering and Business. | |||
Michael S. Parrett | Yes | Yes | Mr. Parrett is currently an independent consultant providing advisory service to various public companies in Canada and the United States. Mr. Parrett is a member of the Board of Fording Inc. and is serving as a Trustee for Fording Canadian Coal Trust as well as the Chairman of Gabriel Resources Limited. He formerly was President of Rio Algom Limited and prior to that Chief Financial Officer of Rio Algom and Falconbridge Limited. Mr. Parrett is a chartered accountant and holds a Bachelor of Arts in Economics from York University. | |||
A. Terence Poole | Yes | Yes | Mr. Poole is currently the Executive Vice President, Corporate Strategy and Development of Nova Chemicals Corporation. Prior to assuming his present position in 2000, he held various senior management positions with Nova and other companies. Mr. Poole brings extensive senior financial management, accounting, capital and debt market experience to Pengrowth. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Accountant designation. | |||
Kirby L. Hedrick | Yes | Yes | Mr. Hedrick has extensive engineering and senior management experience in the United States and internationally, retiring in 2000 as Executive Vice President, Upstream of Phillips Petroleum. He currently serves on the board of Noble Energy Inc. Mr. Hedrick received a Bachelor of Science and Mechanical Engineering degree from the University of Evansville, Indiana in 1975. He completed the Stanford Executive Program in 1997 and the Stanford Corporate Governance Program in 2003. |
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2005 | 2004 | |||||||
Category | $M | $M | ||||||
Audit Fees | 305 | 624 | ||||||
Audit Related Fees | — | — | ||||||
Tax Fees | 104 | 102 | ||||||
All Other Fees | 6 | 6 | ||||||
Total | 415 | 732 | ||||||
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• | global energy policy, including the ability of OPEC to set and maintain production levels, for oil; | ||
• | political conditions in the Middle East; | ||
• | worldwide economic conditions; | ||
• | weather conditions including weather-related disruptions to the North American natural gas supply; | ||
• | 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. |
• | historical production from the area compared with production rates from similar producing areas; | ||
• | the assumed effect of government regulation; |
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• | 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. |
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• | The Trust Units would cease to be a qualified investment for trusts governed by RRSPs, RRIFs, RESPs and DPSPs, as defined in theTax 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 theTax Actequal to 1 percent 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 |
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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. | |||
• | The Trust would be required to pay a tax under Part XII.2 of theTax Act. The payment of Part XII.2 tax by the Trust may have adverse income tax consequences for certain Unit holders, 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 theTax Act. | ||
• | The 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 theTax Act, potentially subjecting non-residents of Canada to tax pursuant to theTax Acton the disposition (or deemed disposition) of such Trust Units. |
a. | will enforce judgments of United States courts obtained in actions against the 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 the Trust or such persons predicated upon the United States federal securities laws or any such state securities or blue sky laws. |
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• | Because the Trust Units will be publicly traded, the Trust will not be treated as a corporation for U.S. federal income tax purposes only if 90 percent or more of its gross income consists of qualifying income. Although the Trust expects to satisfy the 90 percent requirement at all times, if it fails to satisfy this requirement, it will be treated as a foreign corporation. If the Trust were treated as a corporation, it could be a passive foreign investment company or “PFIC”. Treatment of the Trust as a PFIC could result in a material reduction in the after-tax return to the Unit holders, 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 the 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 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 percent 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. | ||
• | The Trust may not be an appropriate investment for certain types of entities. For example, there is a risk that some of the Trust’s income could be unrelated business taxable income with respect to tax-exempt organizations. Furthermore, we anticipate that substantially all of the Trust’s gross income will not be “qualifying income” for purposes of the rules relating to regulated investment companies. |
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• | restrictions imposed by lenders; | ||
• | accounting delays; | ||
• | delays in the sale or delivery of products; | ||
• | delays in the connection of wells to a gathering system; | ||
• | blowouts or other accidents; | ||
• | adjustments for prior periods; | ||
• | recovery by the operator of expenses incurred in the operation of the properties; or | ||
• | the establishment by the operator of reserves for these expenses. |
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• | the issuance of additional Trust Units; | ||
• | material acquisitions and dispositions of properties; | ||
• | material capital expenditures; | ||
• | borrowing; and | ||
• | the payment of distributable cash. |
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1. | Trust Indenture; | ||
2. | Royalty Indenture; | ||
3. | Unanimous Shareholders Agreement; and | ||
4. | Management Agreement. |
OF THE NEW YORK STOCK EXCHANGE
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• | The NYSE Listed Company Manual requires that each member of the audit committee be financially literate and that at least one member of the audit committee have accounting or related financial management expertise. Pengrowth’s Audit Committee Charter requires that all members of the Audit Committee be financially literate; however, it does not require that any member have accounting or related financial management experience. However, as a matter of practice, Pengrowth’s Audit Committee includes a financial expert and thereby satisfies the NYSE requirement. | ||
• | The NYSE Listed Company Manual requires the audit committee charter to address the duties and responsibilities of the committee which must include that the audit committee must discuss the listed company’s earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies. Pengrowth’s audit committee charter does not require that the audit committee discuss this type of information before being released to the public or provided to analysts or rating agencies; however, Pengrowth has a written Corporate Disclosure Policy and has established a Disclosure Policy Committee consisting of the CEO, CFO, Manager of Investor Relations and Corporate Secretary. Pursuant to the Corporate Disclosure Policy, the Disclosure Policy Committee reviews, and makes determinations in respect of, all new releases issued by Pengrowth, and the release of information to analysts and investors. | ||
• | The NYSE Listed Company Manual requires the written charter of the compensation committee to state that the committee has responsibility to review and approve corporate goals and objectives relevant to CEO compensation, evaluate the CEO’s performance in light of those goals and objectives and either as a committee or together with the other independent directors (as directed by the board) determine and approve the CEO’s compensation level based on this evaluation. In Pengrowth’s structure, the CEO is compensated through the Management Agreement with Pengrowth Management. The charter for Pengrowth’s Compensation Committee recognizes this distinction and requires the committee to review the performance of the Manager and review and consider the terms of the Management Agreement, where appropriate to enter into discussions with the Manager as to amendments or changes to the Management Agreement that are in the interests of Unitholders and to set annual performance targets and plans in connection therewith. | ||
• | The NYSE Listed Company Manual requires shareholder approval of all equity compensation plans and any material revisions to such plans, regardless of whether the security is to be delivered under such plans are newly issued or purchased on the open market, subject to a few limited exceptions. In contrast, the TSX rules require shareholder approval of equity compensation plans only when such plans involve newly issued securities. If the plan provides a procedure for its amendment, the TSX rules require shareholder approval of amendments only where the amendment involves a reduction in the exercise price or an extension of the term of options held by insiders. As a matter or practice, Pengrowth has obtained the approval of its Unitholders to all of its equity compensation plans, regardless of whether the Trust Units to be delivered under such plans are newly issued or purchased on the open market. | ||
• | The NYSE Listed Company Manual requires that the charters of the nominating/corporate governance committee, the audit committee and the compensation committee require an annual performance evaluation of the committee. In addition, the NYSE Listed Company Manual suggests that an issuer’s corporate governance guidelines include a requirement for the board to conduct a self-evaluation at least annually. While Pengrowth’s charters for these committees does not require those committees to perform an annual performance evaluation nor does the Pengrowth’s Corporate Governance Policy require the board to |
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conduct annual self-evaluation, the charter of the Corporate Governance Committee includes the mandate to assess the effectiveness of the board and its committees. | |||
• | The NYSE Listed Company Manual requires the written charter of the compensation committee to provide that the committee must produce a compensation committee report on executive officer compensation for inclusion in the issuer’s annual information circular or annual report. While the Terms of Reference of Pengrowth’s Compensation Committee does not require such a report, in accordance with applicable Canadian securities laws Pengrowth’s annual Information Circular – Proxy Statement contains a report on executive compensation, which is reviewed and approved by the Compensation Committee. | ||
• | The NYSE Listed Company Manual requires the written charter of the audit committee to provide that the audit committee must prepare a report to be included in the issuer’s annual information circular. There is no requirement under Canadian law or under Pengrowth’s audit committee charter to prepare such a report, and it is not Pengrowth’s current practice to prepare such a report. However, read together, the disclosure contained in Pengrowth’s Information Circular – Proxy Statement under the heading ‘Part II – Corporate Governance’, Pengrowth’s Annual Report under the headings ‘Corporate Responsibility’, ‘Corporate Governance Practices’ and ‘Structure and Function’, and herein under the heading ‘Audit Committee’ provides the substance of the disclosure mandated by the NYSE rule. |
Investor Relations | ||
Pengrowth Energy Trust | Toronto Investor Relations | |
Suite 2900, 240 — 4th Ave S.W. | Scotia Plaza, 40 King Street West | |
Calgary, Alberta T2P 4H4 | Suite 3006, Box 106 | |
Telephone: (403) 233-0224 | Toronto, Ontario M5H 3Y2 | |
1-800-223-4122 | Telephone: (416) 362-1748 | |
Fax: (403) 294-0051 | 1-888-744-1111 | |
Fax: (416) 362-8191 |
Website: | www.pengrowth.com | |||
E-mail: | investorrelations@pengrowth.com |
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BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
1. | We have prepared an evaluation of the Company’s reserves data as at December 31, 2005. The reserves data consist of the following: |
(a) | (i) | proved and proved plus probable oil and gas reserves estimated as at December 31, 2005, 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, 2005, using constant prices and costs; and | ||||
(ii) | the related estimated future net revenue. |
2. | 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). | ||
3. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook. | |
4. | 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, 2005, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors: |
Location of | ||||||||||||||||||||||||
Location of | ||||||||||||||||||||||||
Reserves | ||||||||||||||||||||||||
Description and | (Country or | |||||||||||||||||||||||
Independent | Preparation Date of | Foreign | Net Present Value of Future Net Revenue | |||||||||||||||||||||
Qualified Reserves | Evaluation | Geographic | (before income taxes, 10% discount rate - $M) | |||||||||||||||||||||
Evaluator | Report | �� | Area) | Audited | Evaluated | Reviewed | Total | |||||||||||||||||
GLJ Petroleum Consultants | January 16, 2006 | Canada | — | $ | 3,204,481 | — | $ | 3,204,481 |
5. | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. | |
6. | We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates. | |
7. | Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. |
Doug R. Sutton, P. Eng. | ||
VP Corporate Evaluations |
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REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
(a) | (i) | proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast prices and costs; and | ||
(i) | the related estimated future net revenue; and | |||
(b) | (i) | proved oil and gas reserves estimated as at December 31, 2005 using constant prices and costs; and | ||
(i) | the related estimated future net revenue. |
(c) | reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator; | |
(d) | 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 | |
(e) | reviewed the reserves data with management and the independent qualified reserves evaluator. |
(f) | the content and filing with securities regulatory authorities of the reserves data and other oil and gas information; | |
(g) | the filing of the report of the independent qualified reserves evaluator on the reserves data; and | |
(h) | the content and filing of this report. |
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“James S. Kinnear” | ||
Chairman, President and Chief Executive Officer | ||
Pengrowth Corporation | ||
“William G. Christensen” | ||
Vice President, Strategic Planning and Reservoir Exploitation | ||
Pengrowth Corporation | ||
“Stanley H. Wong” | ||
Director | ||
Pengrowth Corporation | ||
“Kirby L. Hedrick” | ||
Director | ||
Pengrowth Corporation | ||
March 29, 2006 |
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C-1
BOARD OF DIRECTORS OF PENGROWTH CORPORATION (THE “COMPANY”)
JULY 30, 2001
AND AMENDED AND RESTATED MARCH 28, 2006
I. | Audit Committee purpose: |
• | Monitor the performance of the Company’s internal audit function and the integrity of the Company’s financial reporting process and systems of internal controls regarding finance, accounting, and legal compliance. | ||
• | Monitor the independence and performance of the Company’s external auditors. | ||
• | Provide an avenue of communication among the external auditors, the internal auditors, management and the Board of Directors. |
II. | Audit Committee Composition and Meetings | |
Audit Committee members shall meet the requirements of applicable securities laws and the stock exchanges on which Pengrowth Energy Trust trades. The Audit Committee shall be comprised of three or more directors as determined by the Board, each of whom shall be “independent” and “financially literate”, as those terms are defined in Multilateral Instrument 52-110 Audit Committees of the Canadian Securities Administrators. | ||
Audit Committee members shall be appointed by the Board. If an audit committee Chair is not designated or present, the members of the Committee may designate a Chair by majority vote of the Committee membership. | ||
The Committee shall meet at least four times annually, or more frequently as circumstances dictate. The Audit Committee Chair shall prepare and/or approve an agenda in advance of each meeting. The Committee should meet privately in executive sessions at least annually with management, the internal auditors and the external auditors and as a Committee to discuss any matters that the Committee, management, the internal auditors or the external auditors believe should be discussed. In addition, the Committee, or at least its Chair, should communicate with management, the internal auditors and the external auditors quarterly to review the Company’s financial statements and significant findings based upon the auditors’ limited review procedures. | ||
III. | Audit Committee Responsibilities and Duties | |
Review Procedures |
1. | Review and reassess the adequacy of this Charter at least annually. Submit the Charter to the Board of Directors for approval and have the document published at least every three years in accordance with SEC regulations. | ||
2. | Review the Company’s annual audited financial statements, management’s discussion and analysis and annual and interim earnings press releases prior to filing or public distribution. This review |
C-2
should include discussions with management, the internal auditors and the external auditors of significant issues regarding accounting principles, practices and judgements. |
3. | In consultation with management, the internal auditors and the external auditors, consider the integrity of the Company’s financial reporting processes and controls and the performance of the Company’s internal financial accounting staff. Discuss significant financial risk exposures and the steps management has taken to monitor, control and report such exposures. Review significant findings prepared by the internal or external auditors together with management’s responses. | ||
4. | Review with financial management, the internal auditors and the external auditors the Company’s quarterly financial results and accompanying management’s discussion and analysis prior to the release of earnings and/or the Company’s quarterly financial statements prior to filing or public distribution. Discuss any significant changes to the Company’s accounting principles and any items required to be communicated by the external auditors in accordance with Assurance and Related Services Guideline #11 (AuG-11) (see item 10). | ||
5. | Review with financial management, the internal auditors and the external auditors the Company’s policies relating to risk management and risk assessment. | ||
6. | Meet separately with each of management of the Company, the internal auditors and with the external auditors to discuss difficulties or concerns, specifically: (i) any difficulties encountered in the course of the audit work, including any restrictions on the scope of activities or access to requested information, and any significant disagreements with management; (ii) any changes required in the planned scope of the audit; and (iii) the responsibilities, budget, and staffing of the internal audit function, and report to the Board of Directors on such meetings. |
7. | Review the annual audit plans of the internal auditors. | ||
8. | Review the significant findings prepared by the internal auditors and recommendations issued by any external party relating to internal audit issues, together with management’s response thereto. | ||
9. | Review the adequacy of the resources of the internal auditors to ensure the objectivity and independence of the internal audit function. | ||
10. | Consult with management on management’s appointment, replacement, reassignment or dismissal of the internal auditors. | ||
11. | Ensure that the internal auditors have access to the Chair, the Chair of the Board of Directors and the Chief Executive Officer. |
12. | The external auditors are ultimately accountable to the Audit Committee and the Board of Directors. The Audit Committee is directly responsible for overseeing the work of the external auditors, shall review the independence and performance of the external auditors and shall annually recommend to the Board of Directors the appointment of the external auditors or approve any discharge of auditors when circumstances warrant. The Audit Committee shall, on an annual basis, obtain and review a report by the external auditor describing: (i) the Company’s internal quality control procedures; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the Company, or by an inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the Company, and any steps taken to deal with any such issues; and (iii) all relationships between the independent auditor and the Company. |
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13. | Approve the fees and other significant compensation to be paid to the external auditors. | ||
14. | Pre-approve all non-audit services to be provided to the Company or its subsidiary entities by the Company’s external auditors. | ||
15. | On an annual basis, the Committee should review and discuss with the external auditors all significant relationships they have with the Company that could impair the auditors’ independence. | ||
16. | The Committee shall review the external auditors audit plan – discuss scope, staffing, locations, and reliance upon management and general audit approach. | ||
17. | Prior to releasing the year-end earnings, discuss the results of the audit with the external auditors. | ||
18. | Consider the external auditors’ judgments about the quality and appropriateness of the Company’s accounting principles as applied in its financial reporting. | ||
19. | Be responsible for the resolution of disagreements between management and the external auditors regarding financial performance. |
20. | Establish procedures for: (i) the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and (ii) the confidential and anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters. | ||
21. | Review and approve the Company’s hiring policies regarding partners, employees and former partners and employees of the present and former external auditors of the Company. | ||
22. | On at least an annual basis, review with the Company’s counsel, any legal matters that could have a significant impact on the organization’s financial statements, the Company’s compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies. | ||
23. | Annually prepare a report to shareholders as required by the Securities and Exchange Commission. The report should be included in the Company’s annual proxy statement. | ||
24. | Perform any other activities consistent with this Charter, the Company’s by-laws, and governing law as the Committee or the Board deems necessary or appropriate. | ||
25. | Maintain minutes of meetings and periodically report to the Board of Directors on significant results of the foregoing activities. |
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(INCLUDED ON PAGES 54 THROUGH 80 OF THE PENGROWTH ENERGY TRUST 2005 ANNUAL REPORT)
(%)
Note: Assumes reinvestment of distributions in the trust at month end.
(NYSE) and Class B trust units (TSX).
PENGROWTH ENERGY TRUST
2005 ANNUAL REPORT
PENGROWTH ENERGY TRUST
• | Oil and gas sales increased 41 percent to $1.15 billion in 2005 resulting in record net income of $326 million, an increase of 112 percent over 2004. |
• | Production for 2005 averaged 59,357 barrels of oil equivalent (boe) per day, an increase of more than ten percent versus 2004. Fourth quarter production averaged 61,442 boe per day, an increase of four percent over the previous quarter and seven percent over the comparable period in 2004. |
• | Distributable cash reached a new high in 2005 at $620 million, an increase of 54 percent over 2004. Fourth quarter distributable cash increased 87 percent versus 2004 to $196 million, the highest level of distributable cash generated in any quarter in Pengrowth’s history. |
• | Distributions paid or declared to unitholders increased 23 percent to $446 million or $2.82 per trust unit in 2005 from $363 million or $2.63 per trust unit in 2004. Pengrowth’s monthly distribution was increased in December 2005 to an annualized rate of $3.00 per trust unit. |
• | Pengrowth’s payout ratio to unitholders for the full year and fourth quarter of 2005 reached record lows of 72 percent and 61 percent of cash generated from operations, respectively. |
• | Pengrowth’s 2005 development expenditures were essentially fully funded through withholdings from distributable cash. |
• | During the year Pengrowth spent a combined total of $176 million on maintenance and development projects ending the year with proved plus probable (P50) reserves of 219.4 million barrels of oil equivalent (mmboe) compared to 218.6 mmboe at year end 2004. Pengrowth’s P50 reserves were replaced through the addition of 16.7 mmboe related to acquisitions and 8.6 mmboe resulting from drilling activity, improved recoveries and technical revisions. Additions were offset by production of 21.7 mmboe and divestitures of 2.8 mmboe. |
• | Pengrowth’s average realized commodity price (after hedging) increased 28 percent to $53.02 per boe in 2005, from $41.33 in 2004. |
• | Operating netbacks increased 33 percent to $32.54 per boe (after hedging) versus $24.51 per boe in 2004. Combined hedging losses totaled $3.04 per boe in 2005 versus $3.52 per boe in 2004. |
• | On February 28, 2005, Pengrowth acquired an additional 11.89 percent working interest in the Swan Hills property for $87 million. This acquisition increased Pengrowth’s total interest in the property to 22.34 percent. |
• | On April 29, 2005, Pengrowth successfully completed the acquisition of all of the issued and outstanding shares of Crispin adding approximately 1,900 boe per day of production to our portfolio. |
• | On December 1, 2005, Pengrowth completed a £50 million private placement of senior unsecured ten year notes. |
• | As at December 31, 2005, Pengrowth had generated a combined three-year weighted average compound total return of 36 percent per annum for Class A and Class B unitholders. |
2005 ANNUAL REPORT
Three months ended December 31 | Twelve months ended December 31 | |||||||||||||||||||||||||||
(thousands, except per unit amounts) | 2005 | 2004 | % Change | 2005 | 2004 | % Change | ||||||||||||||||||||||
INCOME STATEMENT | ||||||||||||||||||||||||||||
Oil and gas sales | $ | 353,923 | $ | 223,183 | (2) | 59 | $ | 1,151,510 | $ | 815,751 | (2) | 41 | ||||||||||||||||
Net income | $ | 116,663 | $ | 31,138 | 275 | $ | 326,326 | $ | 153,745 | 112 | ||||||||||||||||||
Net income per trust unit | $ | 0.73 | $ | 0.23 | 217 | $ | 2.08 | $ | 1.15 | 81 | ||||||||||||||||||
Cash generated from operations | $ | 196,588 | $ | 93,287 | 111 | $ | 618,070 | $ | 404,167 | 53 | ||||||||||||||||||
Cash generated from operations per trust unit | $ | 1.23 | $ | 0.68 | 81 | $ | 3.93 | $ | 3.03 | 30 | ||||||||||||||||||
Distributable cash(1) | $ | 195,879 | $ | 104,958 | (2) | 87 | $ | 619,739 | $ | 401,178 | (2) | 54 | ||||||||||||||||
Distributable cash per trust unit(1) | $ | 1.23 | $ | 0.77 | 60 | $ | 3.94 | $ | 3.01 | 31 | ||||||||||||||||||
Distributions paid or declared | $ | 119,858 | $ | 96,466 | 24 | $ | 445,977 | $ | 363,061 | 23 | ||||||||||||||||||
Distributions paid or declared per trust unit | $ | 0.75 | $ | 0.69 | 9 | $ | 2.82 | $ | 2.63 | 7 | ||||||||||||||||||
Weighted average number of trust units outstanding | 159,528 | 136,916 | 17 | 157,127 | 133,395 | 18 | ||||||||||||||||||||||
BALANCE SHEET | ||||||||||||||||||||||||||||
Working capital | $ | (112,205 | ) | $ | (78,546 | ) | 43 | |||||||||||||||||||||
Property, plant and equipment and other assets | $ | 2,067,988 | $ | 1,989,288 | 4 | |||||||||||||||||||||||
Long term debt | $ | 368,089 | $ | 345,400 | 7 | |||||||||||||||||||||||
Unitholders’ equity | $ | 1,475,996 | $ | 1,462,211 | 1 | |||||||||||||||||||||||
Unitholders’ equity per trust unit | $ | 9.23 | $ | 9.56 | (3 | ) | ||||||||||||||||||||||
Number of trust units outstanding at year end | 159,864 | 152,973 | 5 | |||||||||||||||||||||||||
DAILY PRODUCTION | ||||||||||||||||||||||||||||
Crude oil (barrels) | 21,179 | 20,118 | 5 | 20,799 | 20,817 | 0 | ||||||||||||||||||||||
Heavy oil (barrels) | 5,410 | 5,819 | (7 | ) | 5,623 | 3,558 | 58 | |||||||||||||||||||||
Natural gas (mcf) | 168,862 | 156,621 | 8 | 161,056 | 144,277 | 12 | ||||||||||||||||||||||
Natural gas liquids (barrels) | 6,710 | 5,385 | 25 | 6,093 | 5,281 | 15 | ||||||||||||||||||||||
Total production (boe) | 61,442 | 57,425 | 7 | 59,357 | 53,702 | 10 | ||||||||||||||||||||||
Total production (mboe) | 5,653 | 5,283 | 7 | 21,665 | 19,655 | 10 | ||||||||||||||||||||||
PRODUCTION PROFILE | ||||||||||||||||||||||||||||
Crude oil | 34 | % | 35 | % | 35 | % | 39 | % | ||||||||||||||||||||
Heavy oil | 9 | % | 10 | % | 10 | % | 6 | % | ||||||||||||||||||||
Natural gas | 46 | % | 46 | % | 45 | % | 45 | % | ||||||||||||||||||||
Natural gas liquids | 11 | % | 9 | % | 10 | % | 10 | % | ||||||||||||||||||||
AVERAGE REALIZED PRICES | ||||||||||||||||||||||||||||
(AFTER HEDGING) | ||||||||||||||||||||||||||||
Crude oil (per barrel) | $ | 59.40 | $ | 44.76 | 33 | $ | 58.59 | $ | 43.21 | 36 | ||||||||||||||||||
Heavy oil (per barrel) | $ | 31.77 | $ | 26.99 | 18 | $ | 33.32 | $ | 32.45 | 3 | ||||||||||||||||||
Natural gas (per mcf) | $ | 11.97 | $ | 7.02 | 71 | $ | 8.76 | $ | 6.80 | 29 | ||||||||||||||||||
Natural gas liquids (per barrel) | $ | 58.46 | $ | 48.04 | 22 | $ | 54.22 | $ | 42.21 | 28 | ||||||||||||||||||
Average realized price per boe | $ | 62.55 | $ | 42.08 | (2) | 49 | $ | 53.02 | $ | 41.33 | (2) | 28 | ||||||||||||||||
PROVED PLUS PROBABLE RESERVES | ||||||||||||||||||||||||||||
Crude oil (mbbls) | 98,684 | 94,066 | 5 | |||||||||||||||||||||||||
Heavy oil (mbbls) | 15,790 | 18,245 | (13 | ) | ||||||||||||||||||||||||
Natural gas (bcf) | 516 | 521 | (1 | ) | ||||||||||||||||||||||||
Natural gas liquids (mbbls) | 18,985 | 19,395 | (2 | ) | ||||||||||||||||||||||||
Total oil equivalent (mboe) | 219,396 | 218,613 | 0 | |||||||||||||||||||||||||
(1)See the section entitled “Non-GAAP Financial Measures” | ||
(2)Restated to conform to presentation adopted in the current year |
PENGROWTH ENERGY TRUST
Three months ended | Twelve months ended | |||||||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | ||||||||||||||||||||||||
Light crude oil (bbls)(1) | 21,179 | 20,660 | 20,118 | 20,799 | 20,817 | |||||||||||||||||||||||
Heavy oil (bbls)(1) | 5,410 | 5,405 | 5,819 | 5,623 | 3,558 | |||||||||||||||||||||||
Natural gas (mcf) | 168,862 | 164,288 | 156,621 | 161,056 | 144,277 | |||||||||||||||||||||||
Natural gas liquids (bbls)(1) | 6,710 | 5,448 | 5,385 | 6,093 | 5,281 | |||||||||||||||||||||||
Total boe per day | 61,442 | 58,894 | 57,425 | 59,357 | 53,702 | |||||||||||||||||||||||
(1)bbls refers to barrels |
2005 ANNUAL REPORT
(Cdn$) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Light crude oil (per bbl) | 67.00 | 74.37 | 55.24 | 65.47 | 50.72 | ||||||||||||||||||||
after hedging | 59.40 | 63.95 | 44.76 | 58.59 | 43.21 | ||||||||||||||||||||
Heavy oil (per bbl) | 31.77 | 47.74 | 26.99 | 33.32 | 32.45 | ||||||||||||||||||||
Natural gas (per mcf) | 12.80 | 8.69 | 7.25 | 8.99 | 7.03 | ||||||||||||||||||||
after hedging | 11.97 | 8.57 | 7.02 | 8.76 | 6.80 | ||||||||||||||||||||
Natural gas liquids (per bbl) | 58.46 | 57.75 | 48.04 | 54.22 | 42.21 | ||||||||||||||||||||
Total per boe | 67.43 | 60.06 | 46.38 | (3) | 56.06 | 44.85 | (3) | ||||||||||||||||||
after hedging | 62.55 | 56.07 | 42.08 | (3) | 53.02 | 41.33 | (3) | ||||||||||||||||||
Benchmark Prices | |||||||||||||||||||||||||
WTI oil (U.S. $ per bbl) | 60.05 | 63.31 | 48.27 | 56.70 | 41.47 | ||||||||||||||||||||
AECO spot gas (Cdn $ per gj)(1) | 11.08 | 7.75 | 6.72 | 8.04 | 6.44 | ||||||||||||||||||||
NYMEX gas (U.S. $ per mmbtu)(2) | 12.97 | 8.49 | 7.11 | 8.62 | 6.16 | ||||||||||||||||||||
Currency (U.S. $/Cdn $) | 0.85 | 0.83 | 0.82 | 0.83 | 0.77 | ||||||||||||||||||||
(1) gj refers to gigajoules | ||
(2) mmbtu refers to millions of British thermal units | ||
(3) Prior years restated to conform to presentation adopted in current year |
Three months ended | Twelve months ended | ||||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Light crude oil ($ million) | 14.8 | 19.8 | 19.4 | 52.2 | 57.2 | ||||||||||||||||||||
Light crude oil ($ per bbl) | 7.60 | 10.42 | 10.48 | 6.88 | 7.51 | ||||||||||||||||||||
Natural gas ($ million) | 12.9 | 1.8 | 3.3 | 13.6 | 11.9 | ||||||||||||||||||||
Natural gas ($ per mcf) | 0.83 | 0.12 | 0.23 | 0.23 | 0.23 | ||||||||||||||||||||
Combined ($ million) | 27.7 | 21.6 | 22.7 | 65.8 | 69.1 | ||||||||||||||||||||
Combined ($ per boe) | 4.88 | 3.99 | 4.30 | 3.04 | 3.52 | ||||||||||||||||||||
PENGROWTH ENERGY TRUST
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||||||||||||||||||||||
Dec. 31, | % of | Sep. 30, | % of | Dec. 31, | % of | Dec. 31, | % of | Dec. 31, | % of | ||||||||||||||||||||||||||||||||||||
Sales Revenue | 2005 | total | 2005 | total | 2004 | total | 2005 | total | 2004 | total | |||||||||||||||||||||||||||||||||||
Natural gas | 186.0 | 53 | 129.5 | 43 | 101.2 | 45 | 514.9 | 45 | 359.3 | 44 | |||||||||||||||||||||||||||||||||||
Light crude oil | 115.7 | 33 | 121.6 | 40 | 82.8 | 37 | 444.8 | 39 | 329.2 | 40 | |||||||||||||||||||||||||||||||||||
Natural gas liquids | 36.1 | 10 | 28.9 | 9 | 23.8 | 11 | 120.6 | 10 | 81.6 | 10 | |||||||||||||||||||||||||||||||||||
Heavy oil | 15.8 | 4 | 23.7 | 8 | 14.5 | 7 | 68.4 | 6 | 42.3 | 5 | |||||||||||||||||||||||||||||||||||
Brokered sales/sulphur | 0.3 | — | 0.8 | — | 0.9 | — | 2.8 | — | 3.4 | 1 | |||||||||||||||||||||||||||||||||||
Total oil and gas sales | 353.9 | — | 304.5 | — | 223.2 | — | 1,151.5 | — | 815.8 | — | |||||||||||||||||||||||||||||||||||
($ millions) | Natural gas | Light oil | NGLs | Heavy oil | Other | Total | ||||||||||||||||||
Year ended December 31, 2004 | 359.3 | 329.2 | 81.6 | 42.3 | 3.4 | 815.8 | ||||||||||||||||||
Effect of change in product prices | 115.3 | 112.0 | 26.7 | 1.8 | — | 255.8 | ||||||||||||||||||
Effect of change in sales volumes | 42.0 | (1.4 | ) | 12.3 | 24.3 | — | 77.2 | |||||||||||||||||
Effect of hedging losses | (1.7 | ) | 5.0 | — | — | — | 3.3 | |||||||||||||||||
Other | — | — | — | — | (0.6 | ) | (0.6 | ) | ||||||||||||||||
Year ended December 31, 2005 | 514.9 | 444.8 | 120.6 | 68.4 | 2.8 | 1,151.5 | ||||||||||||||||||
2005 ANNUAL REPORT
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Light oil transportation | 0.5 | 0.6 | 0.4 | 2.2 | 1.8 | ||||||||||||||||||||
$ per bbl | 0.27 | 0.29 | 0.23 | 0.29 | 0.23 | ||||||||||||||||||||
Natural gas transportation | 1.8 | 1.4 | 2.0 | 5.7 | 6.3 | ||||||||||||||||||||
$ per mcf | 0.12 | 0.09 | 0.14 | 0.10 | 0.12 | ||||||||||||||||||||
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Royalty expense | 68.0 | 57.4 | 49.1 | 213.9 | 160.4 | ||||||||||||||||||||
$ per boe | 12.03 | 10.60 | 9.29 | 9.87 | 8.16 | ||||||||||||||||||||
Royalties as a percent of sales | 19.2 | % | 18.9 | % | 22.0 | % | 18.6 | % | 19.7 | % | |||||||||||||||
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Processing, interest & other income | 4.0 | 2.1 | 4.5 | 17.7 | 14.2 | ||||||||||||||||||||
$ per boe | 0.71 | 0.39 | 0.83 | 0.82 | 0.72 | ||||||||||||||||||||
PENGROWTH ENERGY TRUST
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Operating expenses | 61.2 | 57.4 | 42.6 | 218.1 | 159.7 | ||||||||||||||||||||
$ per boe | 10.83 | 10.59 | 8.06 | 10.07 | 8.13 | ||||||||||||||||||||
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Purchased and capitalized | 14.5 | 6.9 | 8.2 | 34.7 | 20.4 | ||||||||||||||||||||
Amortization | 7.1 | 6.0 | 4.9 | 24.4 | 19.7 | ||||||||||||||||||||
2005 ANNUAL REPORT
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Cash G&A expense | 7.7 | 7.0 | 6.5 | 27.4 | 22.1 | ||||||||||||||||||||
$ per boe | 1.36 | 1.29 | 1.23 | 1.27 | 1.12 | ||||||||||||||||||||
Non-cash G&A expense | 0.8 | 0.6 | 0.4 | 2.9 | 2.3 | ||||||||||||||||||||
$ per boe | 0.14 | 0.11 | 0.08 | 0.13 | 0.12 | ||||||||||||||||||||
Total G&A ($ million) | 8.5 | 7.6 | 6.9 | 30.3 | 24.4 | ||||||||||||||||||||
Total G&A ($ per boe) | 1.50 | 1.40 | 1.31 | 1.40 | 1.24 | ||||||||||||||||||||
PENGROWTH ENERGY TRUST
($ million) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Management Fee | 2.2 | 1.6 | 1.4 | 9.1 | 6.8 | ||||||||||||||||||||
Performance Fee | 2.2 | 1.9 | 1.2 | 6.9 | 6.1 | ||||||||||||||||||||
Total ($ million) | 4.4 | 3.5 | 2.6 | 16.0 | 12.9 | ||||||||||||||||||||
Total ($ per boe) | 0.77 | 0.65 | 0.48 | 0.74 | 0.66 | ||||||||||||||||||||
2005 ANNUAL REPORT
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Depletion and Depreciation | 71.4 | 73.5 | 69.4 | 285.0 | 247.3 | ||||||||||||||||||||
$ per boe | 12.63 | 13.57 | 13.14 | 13.15 | 12.58 | ||||||||||||||||||||
Accretion | 3.6 | 3.6 | 3.2 | 14.2 | 10.6 | ||||||||||||||||||||
$ per boe | 0.64 | 0.66 | 0.60 | 0.65 | 0.54 | ||||||||||||||||||||
PENGROWTH ENERGY TRUST
($ per boe) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Sales price | 62.55 | 56.07 | 42.08 | 53.02 | 41.33 | ||||||||||||||||||||
Other production income | 0.06 | 0.13 | 0.17 | 0.13 | 0.17 | ||||||||||||||||||||
62.61 | 56.20 | 42.25 | 53.15 | 41.50 | |||||||||||||||||||||
Processing, interest and other income | 0.71 | 0.39 | 0.83 | 0.82 | 0.72 | ||||||||||||||||||||
Royalties | (12.02 | ) | (10.60 | ) | (9.29 | ) | (9.87 | ) | (8.16 | ) | |||||||||||||||
Operating expenses | (10.83 | ) | (10.59 | ) | (8.07 | ) | (10.07 | ) | (8.13 | ) | |||||||||||||||
Transportation costs | (0.41 | ) | (0.36 | ) | (0.47 | ) | (0.36 | ) | (0.42 | ) | |||||||||||||||
Amortization of injectants | (1.25 | ) | (1.10 | ) | (0.94 | ) | (1.13 | ) | (1.00 | ) | |||||||||||||||
Operating netback | 38.81 | 33.94 | 24.31 | 32.54 | 24.51 | ||||||||||||||||||||
2005 ANNUAL REPORT
($ per bbl) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Sales price | 59.40 | 63.95 | 44.76 | 58.59 | 43.21 | ||||||||||||||||||||
Other production income | 0.17 | 0.37 | 0.48 | 0.37 | 0.45 | ||||||||||||||||||||
59.57 | 64.32 | 45.24 | 58.96 | 43.66 | |||||||||||||||||||||
Processing, interest and other income | 0.34 | 0.64 | 0.51 | 0.47 | 0.46 | ||||||||||||||||||||
Royalties | (6.47 | ) | (11.03 | ) | (9.65 | ) | (8.64 | ) | (7.62 | ) | |||||||||||||||
Operating expenses | (14.32 | ) | (12.85 | ) | (9.17 | ) | (12.28 | ) | (9.31 | ) | |||||||||||||||
Transportation costs | (0.27 | ) | (0.29 | ) | (0.23 | ) | (0.29 | ) | (0.23 | ) | |||||||||||||||
Amortization of injectants | (3.63 | ) | (3.14 | ) | (2.67 | ) | (3.21 | ) | (2.58 | ) | |||||||||||||||
Operating netback | 35.22 | 37.65 | 24.03 | 35.01 | 24.38 | ||||||||||||||||||||
($ per bbl) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Sales price | 31.77 | 47.74 | 26.99 | 33.32 | 32.45 | ||||||||||||||||||||
Processing, interest and other income | 0.74 | (0.83 | ) | — | 0.36 | — | |||||||||||||||||||
Royalties | (2.98 | ) | (8.00 | ) | (4.19 | ) | (4.53 | ) | (4.87 | ) | |||||||||||||||
Operating expenses | (11.60 | ) | (16.30 | ) | (9.44 | ) | (15.65 | ) | (9.85 | ) | |||||||||||||||
Operating netback | 17.93 | 22.61 | 13.36 | 13.50 | 17.73 | ||||||||||||||||||||
($ per mcf) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Sales price | 11.97 | 8.57 | 7.02 | 8.76 | 6.80 | ||||||||||||||||||||
Processing, interest and other income | 0.19 | 0.09 | 0.24 | 0.23 | 0.20 | ||||||||||||||||||||
Royalties | (2.62 | ) | (1.47 | ) | (1.34 | ) | (1.70 | ) | (1.26 | ) | |||||||||||||||
Operating expenses | (1.38 | ) | (1.31 | ) | (1.16 | ) | (1.24 | ) | (1.15 | ) | |||||||||||||||
Transportation costs | (0.12 | ) | (0.09 | ) | (0.14 | ) | (0.10 | ) | (0.12 | ) | |||||||||||||||
Operating netback | 8.04 | 5.79 | 4.62 | 5.95 | 4.47 | ||||||||||||||||||||
PENGROWTH ENERGY TRUST
($ per bbl) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Sales price | 58.46 | 57.75 | 48.04 | 54.22 | 42.21 | ||||||||||||||||||||
Royalties | (21.29 | ) | (20.57 | ) | (19.37 | ) | (17.66 | ) | (15.43 | ) | |||||||||||||||
Operating expenses | (10.05 | ) | (10.13 | ) | (7.87 | ) | (9.04 | ) | (7.94 | ) | |||||||||||||||
Transportation costs | — | — | (0.10 | ) | — | (0.10 | ) | ||||||||||||||||||
Operating netback | 27.12 | 27.05 | 20.70 | 27.52 | 18.74 | ||||||||||||||||||||
69
2005 ANNUAL REPORT
($ thousands, except per trust unit amounts) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Cash generated from operations | 196,588 | 158,976 | 93,287 | 618,070 | 404,167 | ||||||||||||||||||||
Change in non-cash operating working capital | (7,993 | ) | (789 | ) | 8,576 | (9,833 | ) | (1,173 | ) | ||||||||||||||||
Change in deferred injectants | 7,411 | 892 | 3,228 | 10,265 | 746 | ||||||||||||||||||||
Change in remediation trust funds | 784 | (272 | ) | 32 | (20 | ) | (917 | ) | |||||||||||||||||
Change in deferred charges | (793 | ) | 2,818 | (473 | ) | 1,235 | (1,893 | ) | |||||||||||||||||
Other | (118 | ) | 384 | 308 | 22 | 248 | |||||||||||||||||||
Distributable cash | 195,879 | 162,009 | 104,958 | 619,739 | 401,178 | ||||||||||||||||||||
Allocation of Distributable Cash | |||||||||||||||||||||||||
Cash withheld | 76,021 | 52,156 | 8,492 | 173,762 | 38,117 | ||||||||||||||||||||
Distributions paid or declared | 119,858 | 109,853 | 96,466 | 445,977 | 363,061 | ||||||||||||||||||||
Distributable cash | 195,879 | 162,009 | 104,958 | 619,739 | 401,178 | ||||||||||||||||||||
Distributable cash per trust unit | 1.23 | 1.02 | 0.77 | 3.94 | 3.01 | ||||||||||||||||||||
Distributions paid or declared per trust unit | 0.75 | 0.69 | 0.69 | 2.82 | 2.63 | ||||||||||||||||||||
Payout ratio(1) | 61 | % | 69 | % | 103 | % | 72 | % | 90 | % | |||||||||||||||
(1) | Payout ratio is calculated as distributions paid or declared divided by cash generated from operations. |
70
PENGROWTH ENERGY TRUST
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||
Dec. 31, 2005 | Sep. 30, 2005 | Dec. 31, 2004 | Dec. 31, 2005 | Dec. 31, 2004 | |||||||||||||||||||||
Geological and geophysical | — | 0.2 | 0.2 | 1.4 | 0.6 | ||||||||||||||||||||
Drilling and completions | 41.1 | 29.8 | 36.2 | 130.3 | 111.5 | ||||||||||||||||||||
Plant and facilities | 10.2 | 10.0 | 17.7 | 34.1 | 49.0 | ||||||||||||||||||||
Land purchases | 8.8 | 0.8 | — | 9.9 | — | ||||||||||||||||||||
Development capital | 60.1 | 40.8 | 54.1 | 175.7 | 161.1 | ||||||||||||||||||||
Acquisitions | — | — | — | 175.1 | 573.0 | ||||||||||||||||||||
Total capital expenditures and acquisitions | 60.1 | 40.8 | 54.1 | 350.8 | 734.1 | ||||||||||||||||||||
71
2005 ANNUAL REPORT
72
PENGROWTH ENERGY TRUST
Twelve months ended December 31 | ||||||||||
2005 | 2004 | |||||||||
Cash generated from operations to interest expense (times) | 29 | 13 | ||||||||
Long term debt to cash generated from operations (times) | 0.6 | 0.9 | ||||||||
Long term debt to debt plus book equity (%) | 20 | 19 | ||||||||
73
2005 ANNUAL REPORT
($ thousands) | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | |||||||||||||||||||||
Long term debt(1) | — | — | — | — | 174,450 | 193,639 | 368,089 | |||||||||||||||||||||
Interest payments on long term debt(2) | 17,298 | 17,298 | 17,298 | 17,298 | 11,564 | 34,546 | 115,302 | |||||||||||||||||||||
Note payable | 20,000 | — | — | — | — | — | 20,000 | |||||||||||||||||||||
Operating leases | ||||||||||||||||||||||||||||
Office rent | 2,030 | 2,070 | 3,096 | 3,055 | 3,036 | 21,529 | 34,816 | |||||||||||||||||||||
Vehicle leases | 852 | 776 | 604 | 306 | 91 | — | 2,629 | |||||||||||||||||||||
2,882 | 2,846 | 3,700 | 3,361 | 3,127 | 21,529 | 37,445 | ||||||||||||||||||||||
Purchase obligations | ||||||||||||||||||||||||||||
Pipeline transportation | 43,839 | 38,197 | 34,981 | 29,813 | 11,748 | 53,525 | 212,103 | |||||||||||||||||||||
Capital expenditures | 33,323 | 7,098 | 294 | — | — | — | 40,715 | |||||||||||||||||||||
CO2 purchases | 5,119 | 4,357 | 4,198 | 4,232 | 4,267 | 18,728 | 40,901 | |||||||||||||||||||||
82,281 | 49,652 | 39,473 | 34,045 | 16,015 | 72,253 | 293,719 | ||||||||||||||||||||||
Remediation trust fund payments | 250 | 250 | 250 | 250 | 250 | 11,250 | 12,500 | |||||||||||||||||||||
122,711 | 70,046 | 60,721 | 54,954 | 205,406 | 333,217 | 847,055 | ||||||||||||||||||||||
(1) | Foreign dollar denominated debt due as follows: $150 million U.S. in April 2010, $50 million U.S. in April 2013 and £50 million in December 2015, translated at the Dec 31, 2005 exchange rate. | |
(2) | Interest payments on foreign denominated debt, calculated based on Dec 31, 2005 foreign exchange rate. |
74
PENGROWTH ENERGY TRUST
High | Low | Close | Volume (000’s) | Value ($ millions) | ||||||||||||||||
TSX — PGF.A ($ Cdn) | ||||||||||||||||||||
20051st quarter | 28.29 | 22.15 | 24.03 | 2,049 | �� | 53.3 | ||||||||||||||
2nd quarter | 27.90 | 23.95 | 27.20 | 1,798 | 46.4 | |||||||||||||||
3rd quarter | 30.10 | 26.30 | 29.50 | 2,047 | 58.0 | |||||||||||||||
4th quarter | 29.80 | 23.64 | 27.41 | 1,324 | 35.2 | |||||||||||||||
Year | 30.10 | 22.15 | 27.41 | 7,218 | 192.9 | |||||||||||||||
20041st quarter | ||||||||||||||||||||
2nd quarter | ||||||||||||||||||||
3rd quarter | 24.19 | 19.10 | 22.67 | 1,672 | 35.5 | |||||||||||||||
4th quarter | 26.33 | 20.03 | 24.93 | 2,607 | 58.9 | |||||||||||||||
Year | 26.33 | 19.10 | 24.93 | 4,279 | 94.4 | |||||||||||||||
TSX — PGF.B ($ Cdn) | ||||||||||||||||||||
20051st quarter | 19.90 | 16.10 | 17.05 | 29,219 | 543.7 | |||||||||||||||
2nd quarter | 19.01 | 16.37 | 18.40 | 19,370 | 342.5 | |||||||||||||||
3rd quarter | 21.26 | 18.25 | 20.58 | 22,738 | 441.0 | |||||||||||||||
4th quarter | 23.38 | 17.27 | 22.65 | 19,747 | 411.0 | |||||||||||||||
Year | 23.38 | 16.10 | 22.65 | 91,074 | 1,738.2 | |||||||||||||||
20041st quarter | ||||||||||||||||||||
2nd quarter | ||||||||||||||||||||
3rd quarter | 20.00 | 18.03 | 18.87 | 5,588 | 105.6 | |||||||||||||||
4th quarter | 20.04 | 17.51 | 18.50 | 16,007 | 301.8 | |||||||||||||||
Year | 20.04 | 17.51 | 18.50 | 21,595 | 407.4 | |||||||||||||||
NYSE — PGH ($ U.S.) | ||||||||||||||||||||
20051st quarter | 22.94 | 18.11 | 20.00 | 24,621 | 515.1 | |||||||||||||||
2nd quarter | 22.74 | 19.05 | 22.25 | 16,153 | 335.0 | |||||||||||||||
3rd quarter | 25.75 | 21.55 | 25.42 | 14,502 | 340.3 | |||||||||||||||
4th quarter | 25.56 | 20.00 | 23.53 | 17,808 | 399.7 | |||||||||||||||
Year | 25.75 | 18.11 | 23.53 | 73,084 | 1,590.1 | |||||||||||||||
20041st quarter | ||||||||||||||||||||
2nd quarter | ||||||||||||||||||||
3rd quarter | 18.94 | 14.40 | 17.93 | 21,200 | 350.4 | |||||||||||||||
4th quarter | 21.24 | 15.85 | 20.82 | 31,174 | 574.7 | |||||||||||||||
Year | 21.24 | 14.40 | 20.82 | 52,374 | 925.1 | |||||||||||||||
(1) | July 27, 2004, trust units were re-classified as Class A or Class B trust units. Class A trust units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B. |
75
2005 ANNUAL REPORT
High | Low | Close | Volume (000’s) Value ($ millions) | ||||||||||||||||||||
TSX — PGF.UN ($ Cdn) | |||||||||||||||||||||||
20041st quarter | 21.25 | 15.55 | 17.98 | 30,620 | 567.8 | ||||||||||||||||||
2nd quarter | 19.15 | 16.15 | 18.67 | 18,145 | 328.5 | ||||||||||||||||||
3rd quarter | 19.75 | 18.52 | 19.42 | 3,554 | 68.5 | ||||||||||||||||||
4th quarter | |||||||||||||||||||||||
Year | 21.25 | 15.55 | 19.42 | 52,319 | �� | 964.8 | |||||||||||||||||
NYSE — PGH ($ U.S.) | 16.60 | 12.10 | 13.70 | 36,899 | 525.6 | ||||||||||||||||||
20041st quarter | |||||||||||||||||||||||
2nd quarter | 14.24 | 11.62 | 13.98 | 22,194 | 295.9 | ||||||||||||||||||
3rd quarter | 14.95 | 13.84 | 14.64 | 5,797 | 84.5 | ||||||||||||||||||
4th quarter | |||||||||||||||||||||||
Year | 14.95 | 11.62 | 14.64 | 64,890 | 906.0 | ||||||||||||||||||
(1) | July 27, 2004, trust units were re-classified as Class A or Class B trust units. Class A trust units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B. |
76
PENGROWTH ENERGY TRUST
Q1 | Q2 | Q3 | Q4 | |||||||||||||
2005 | ||||||||||||||||
Oil and gas sales ($000’s) | 239,913 | 253,189 | 304,484 | 353,923 | ||||||||||||
Net income ($000’s) | 56,314 | 53,106 | 100,243 | 116,663 | ||||||||||||
Net income per trust unit ($) | 0.37 | 0.34 | 0.63 | 0.73 | ||||||||||||
Net income per trust unit — diluted ($) | 0.37 | 0.34 | 0.63 | 0.73 | ||||||||||||
Distributable cash ($000’s) | 127,804 | 134,047 | 162,009 | 195,879 | ||||||||||||
Actual distributions paid or declared per trust unit ($) | 0.69 | 0.69 | 0.69 | 0.75 | ||||||||||||
Daily production (boe) | 59,082 | 57,988 | 58,894 | 61,442 | ||||||||||||
Total production (mboe) | 5,317 | 5,277 | 5,418 | 5,653 | ||||||||||||
Average realized price ($ per boe) | 44.97 | 47.79 | 56.07 | 62.55 | ||||||||||||
Operating netback ($ per boe) | 27.70 | 29.26 | 33.94 | 38.81 | ||||||||||||
2004 | ||||||||||||||||
Oil and gas sales ($000’s)(1) | 168,771 | 197,284 | 226,514 | 223,183 | ||||||||||||
Net income ($000’s) | 38,652 | 32,684 | 51,271 | 31,138 | ||||||||||||
Net income per trust unit ($) | 0.31 | 0.24 | 0.38 | 0.23 | ||||||||||||
Net income per trust unit — diluted ($) | 0.31 | 0.24 | 0.38 | 0.23 | ||||||||||||
Distributable cash ($000’s)(1) | 92,895 | 99,021 | 104,304 | 104,958 | ||||||||||||
Actual distributions paid or declared per trust unit ($) | 0.63 | 0.64 | 0.67 | 0.69 | ||||||||||||
Daily production (boe) | 45,668 | 51,451 | 60,151 | 57,425 | ||||||||||||
Total production (mboe) | 4,156 | 4,682 | 5,534 | 5,283 | ||||||||||||
Average realized price ($ per boe)(1) | 40.37 | 41.83 | 40.90 | 42.08 | ||||||||||||
Operating netback ($ per boe) | 25.71 | 25.71 | 22.77 | 24.31 | ||||||||||||
Twelve months ended December 31 | ||||||||||||
($ thousands) | 2005 | 2004 | 2003 | |||||||||
Oil and gas sales(1) | 1,151,510 | 815,751 | 702,732 | |||||||||
Net income | 326,326 | 153,745 | 189,297 | |||||||||
Net income per trust unit | 2.08 | 1.15 | 1.63 | |||||||||
Distributable cash(1) | 619,739 | 401,178 | 345,911 | |||||||||
Actual distributions paid or declared per trust unit | 2.82 | 2.63 | 2.68 | |||||||||
Total assets | 2,391,432 | 2,276,534 | 1,673,718 | |||||||||
Long term financial liabilities(2) | 381,026 | 383,616 | 294,300 | |||||||||
Unitholders’ equity | 1,475,996 | 1,462,211 | 1,159,433 | |||||||||
Number of units outstanding at year end (thousands) | 159,864 | 152,973 | 123,874 | |||||||||
(1) | Prior years restated to conform to presentation adopted in the current year | |
(2) | Long term debt plus long term portion of note payable and contract liabilities |
77
2005 ANNUAL REPORT
• | 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 expenses 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. | |
• | Increased competition for properties will drive the cost of acquisition up and expected returns from the properties down. | |
• | 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. |
78
PENGROWTH ENERGY TRUST
• | The value of Class A trust units and Class B trust units, relative to one another, may be influenced by the different markets in which the trust units trade, the restrictions in entitlement of the Class B trust units to Canadian residents and the limitation in the number of Class A trust units beneath an ownership threshold of 49.75 percent of all trust units outstanding. | |
• | 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. | |
• | 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. |
• | 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 strict 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 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. |
79
2005 ANNUAL REPORT
• | Operating our properties in a safe and prudent manner in order to protect our employees, the public, the environment and our investment; | |
• | Maintaining a balanced portfolio of oil and gas properties in our key focus areas; | |
• | Growing production and reserves through accretive acquisitions and low risk development drilling; | |
• | Increasing our undeveloped land position; | |
• | Continuing to optimize costs and maximize netbacks; | |
• | The selective disposition of oil and gas properties that do not meet our return objectives; | |
• | Continuing to maintain a stable distribution policy while withholding a portion of distributable cash to fund future capital programs. |
80
PENGROWTH ENERGY TRUST
INCLUDING NOTE 20 THEREOF WHICH INCLUDES A RECONCILIATION OF THE
CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES
(signed) | (signed) | |
James S. Kinnear | Christopher G. Webster | |
Chairman, President and | Chief Financial Officer | |
Chief Executive Officer | ||
February 27, 2006 |
81
2005 ANNUAL REPORT
Calgary, Canada
82
PENGROWTH ENERGY TRUST
(Stated in thousands of dollars) | ||||||||||
As at December 31 | 2005 | 2004 | ||||||||
ASSETS | ||||||||||
Current Assets | ||||||||||
Accounts receivable | $ | 127,394 | $ | 104,228 | ||||||
Inventory | — | 439 | ||||||||
127,394 | 104,667 | |||||||||
Remediation Trust Funds (Note 3) | 8,329 | 8,309 | ||||||||
Deferred Charges (Note 11) | 4,886 | 3,651 | ||||||||
Goodwill (Note 4) | 182,835 | 170,619 | ||||||||
Property, Plant And Equipment and Other Assets (Note 5) | 2,067,988 | 1,989,288 | ||||||||
$ | 2,391,432 | $ | 2,276,534 | |||||||
LIABILITIES AND UNITHOLDERS’ EQUITY | ||||||||||
Current Liabilities | ||||||||||
Bank indebtedness | $ | 14,567 | $ | 4,214 | ||||||
Accounts payable and accrued liabilities | 111,493 | 80,423 | ||||||||
Distributions payable to unitholders | 79,983 | 70,456 | ||||||||
Due to Pengrowth Management Limited | 8,277 | 7,325 | ||||||||
Note payable (Note 7) | 20,000 | 15,000 | ||||||||
Current portion of contract liabilities (Note 4) | 5,279 | 5,795 | ||||||||
239,599 | 183,213 | |||||||||
Note Payable (Note 7) | — | 20,000 | ||||||||
Contract Liabilities (Note 4) | 12,937 | 18,216 | ||||||||
Long Term Debt (Note 8) | 368,089 | 345,400 | ||||||||
Asset Retirement Obligations (Note 6) | 184,699 | 171,866 | ||||||||
Future Income Taxes (Note 14) | 110,112 | 75,628 | ||||||||
Trust Unitholders’ Equity | ||||||||||
Trust Unitholders’ capital (Note 10) | 2,514,997 | 2,383,284 | ||||||||
Contributed surplus (Note 10) | 3,646 | 1,923 | ||||||||
Deficit (Note 9) | (1,042,647 | ) | (922,996 | ) | ||||||
1,475,996 | 1,462,211 | |||||||||
Commitments (Note 18) | ||||||||||
Subsequent Event (Note 19) | ||||||||||
$ | 2,391,432 | $ | 2,276,534 | |||||||
(signed) | (signed) | |||
Director | Director |
83
2005 ANNUAL REPORT
(Stated in thousands of dollars) | ||||||||
Years ended December 31 | 2005 | 2004 | ||||||
REVENUES | ||||||||
Oil and gas sales | $ | 1,151,510 | $ | 815,751 | ||||
Processing and other income | 15,091 | 12,390 | ||||||
Royalties, net of incentives | (213,863 | ) | (160,351 | ) | ||||
952,738 | 667,790 | |||||||
Interest and other income | 2,596 | 1,770 | ||||||
Net Revenue | 955,334 | 669,560 | ||||||
EXPENSES | ||||||||
Operating | 218,115 | 159,742 | ||||||
Transportation | 7,891 | 8,274 | ||||||
Amortization of injectants for miscible floods | 24,393 | 19,669 | ||||||
Interest | 21,642 | 29,924 | ||||||
General and administrative | 30,272 | 24,448 | ||||||
Management fee (Note 15) | 15,961 | 12,874 | ||||||
Foreign exchange gain (Note 12) | (6,966 | ) | (17,300 | ) | ||||
Depletion and depreciation | 284,989 | 247,332 | ||||||
Accretion (Note 6) | 14,162 | 10,642 | ||||||
610,459 | 495,605 | |||||||
Income Before Taxes | 344,875 | 173,955 | ||||||
Income Tax Expense (Note 14) | ||||||||
Capital | 6,273 | 4,594 | ||||||
Future | 12,276 | 15,616 | ||||||
18,549 | 20,210 | |||||||
NET INCOME | $ | 326,326 | $ | 153,745 | ||||
Deficit, beginning of year | (922,996 | ) | (713,680 | ) | ||||
Distributions paid or declared | (445,977 | ) | (363,061 | ) | ||||
Deficit, End of Year | $ | (1,042,647 | ) | $ | (922,996 | ) | ||
Net Income Per Trust Unit (Note 16) | ||||||||
Basic | $ | 2.077 | $ | 1.153 | ||||
Diluted | $ | 2.066 | $ | 1.147 | ||||
PENGROWTH ENERGY TRUST
(Stated in thousands of dollars) | ||||||||
Years ended December 31 | 2005 | 2004 | ||||||
CASH PROVIDED BY (USED FOR): | ||||||||
Operating | ||||||||
Net income | $ | 326,326 | $ | 153,745 | ||||
Depletion, depreciation and accretion | 299,151 | 257,974 | ||||||
Future income taxes | 12,276 | 15,616 | ||||||
Contract liability amortization | (5,795 | ) | (4,164 | ) | ||||
Amortization of injectants | 24,393 | 19,669 | ||||||
Purchase of injectants | (34,658 | ) | (20,415 | ) | ||||
Expenditures on remediation | (7,353 | ) | (4,440 | ) | ||||
Unrealized foreign exchange gain (Note 12) | (7,800 | ) | (18,900 | ) | ||||
Trust unit based compensation (Note 10) | 2,932 | 2,264 | ||||||
Deferred charges (Note 11) | (4,961 | ) | — | |||||
Amortization of deferred charges (Note 11) | 3,726 | 1,893 | ||||||
Gain on sale of marketable securities | — | (248 | ) | |||||
Changes in non-cash operating working capital (Note 13) | 9,833 | 1,173 | ||||||
618,070 | 404,167 | |||||||
Financing | ||||||||
Distributions | (436,450 | ) | (344,744 | ) | ||||
Change in long term debt, net | 10,030 | 105,000 | ||||||
Note payable (Note 7) | (15,000 | ) | (10,000 | ) | ||||
Proceeds from issue of trust units | 42,544 | 509,830 | ||||||
(398,876 | ) | 260,086 | ||||||
Investing | ||||||||
Expenditures on property acquisitions | (92,568 | ) | (572,980 | ) | ||||
Expenditures on property, plant and equipment | (175,693 | ) | (161,141 | ) | ||||
Proceeds on property dispositions | 37,617 | — | ||||||
Change in remediation trust fund | (20 | ) | (917 | ) | ||||
Purchase of marketable securities | — | (2,680 | ) | |||||
Proceeds from sale of marketable securities | — | 2,928 | ||||||
Change in non-cash investing working capital (Note 13) | 1,117 | 2,169 | ||||||
(229,547 | ) | (732,621 | ) | |||||
Change in Cash and Term Deposits | (10,353 | ) | (68,368 | ) | ||||
Cash and Term Deposits (Bank Indebtedness) at Beginning of Year | (4,214 | ) | 64,154 | |||||
Cash and Term Deposits (Bank Indebtedness) at End of Year | $ | (14,567 | ) | $ | (4,214 | ) | ||
2005 ANNUAL REPORT
(Tabular amounts are stated in thousands of dollars except per unit amounts.)
PENGROWTH ENERGY TRUST
2005 ANNUAL REPORT
PENGROWTH ENERGY TRUST
2005 ANNUAL REPORT
PENGROWTH ENERGY TRUST
2005 | 2004 | |||||||
Contributions to Judy Creek Remediation Trust Fund | $ | 778 | $ | 906 | ||||
Contributions to SOEP Environmental Restoration Fund | 556 | 548 | ||||||
Expenditures related to Judy Creek Remediation Trust Fund | (1,314 | ) | (537 | ) | ||||
20 | 917 | |||||||
Expenditures on ARO not covered by the trust funds | 6,039 | 3,903 | ||||||
Expenditures on ARO covered by the trust funds | 1,314 | 537 | ||||||
7,353 | 4,440 | |||||||
Total trust fund contributions and ARO expenditures not covered by the trust funds | $ | 7,373 | $ | 5,357 | ||||
Allocation of purchase price: | ||||
Working capital | $ | 1,655 | ||
Property, plant, and equipment | 121,729 | |||
Goodwill | 12,216 | |||
Bank debt | (20,459 | ) | ||
Asset retirement obligations | (4,038 | ) | ||
Future income taxes | (22,208 | ) | ||
$ | 88,895 | |||
Cost of acquisition: | ||||
Trust units issued | $ | 87,960 | ||
Acquisition costs | 935 | |||
$ | 88,895 | |||
2005 ANNUAL REPORT
Allocation of purchase price: | ||||
Working capital | $ | 9,310 | ||
Property, plant, and equipment | 502,924 | |||
Goodwill | 170,619 | |||
Asset retirement obligations | (43,876 | ) | ||
Future income taxes | (60,012 | ) | ||
Contract liabilities | (28,175 | ) | ||
$ | 550,790 | |||
Cost of acquisition: | ||||
Cash and term deposits | $ | 224,700 | ||
Acquisition facility | 325,000 | |||
Acquisition costs | 1,090 | |||
$ | 550,790 | |||
PENGROWTH ENERGY TRUST
2004 Proforma | 2004 Actual | |||||||
(unaudited) | (audited) | |||||||
Oil and gas sales | $ | 897,397 | $ | 815,751 | ||||
Net income | $ | 180,101 | $ | 153,745 | ||||
Net income per unit: | ||||||||
Basic | $ | 1.206 | $ | 1.153 | ||||
Diluted | $ | 1.201 | $ | 1.147 | ||||
2005 | 2004 | |||||||
Property, Plant and Equipment | ||||||||
Property, Plant and Equipment, at cost | $ | 3,340,106 | $ | 2,986,681 | ||||
Accumulated depletion and depreciation | (1,307,424 | ) | (1,022,435 | ) | ||||
Net book value of property, plant and equipment | 2,032,682 | 1,964,246 | ||||||
Other Assets | ||||||||
Deferred injectant costs | 35,306 | 25,042 | ||||||
Net book value of property, plant and equipment and other assets | $ | 2,067,988 | $ | 1,989,288 | ||||
2005 ANNUAL REPORT
Foreign | Edmonton Light | |||||||||||||||
WTI Oil | Exchange Rate | Crude Oil | AECO Gas | |||||||||||||
Year | (U.S.$/bbl) | (U.S.$/Cdn) | (Cdn$/bbl) | (Cdn$/mmbtu) | ||||||||||||
2006 | 57.00 | 0.85 | 66.25 | 10.60 | ||||||||||||
2007 | 55.00 | 0.85 | 64.00 | 9.25 | ||||||||||||
2008 | 51.00 | 0.85 | 59.25 | 8.00 | ||||||||||||
2009 | 48.00 | 0.85 | 55.75 | 7.50 | ||||||||||||
2010 | 46.50 | 0.85 | 54.00 | 7.20 | ||||||||||||
2011 | 45.00 | 0.85 | 52.25 | 6.90 | ||||||||||||
2012 | 45.00 | 0.85 | 52.25 | 6.90 | ||||||||||||
2013 | 46.00 | 0.85 | 53.25 | 7.05 | ||||||||||||
2014 | 46.75 | 0.85 | 54.25 | 7.20 | ||||||||||||
2015 | 47.75 | 0.85 | 55.50 | 7.40 | ||||||||||||
2016 | 48.75 | 0.85 | 56.50 | 7.55 | ||||||||||||
Escalate thereafter | 2.0% per year | 2.0% per year | 2.0% per year | |||||||||||||
2005 | 2004 | |||||||
Asset retirement obligations, beginning of year | $ | 171,866 | $ | 102,528 | ||||
Increase (decrease) in liabilities during the year related to: | ||||||||
Acquisitions | 6,347 | 44,368 | ||||||
Disposals | (3,844 | ) | — | |||||
Additions | 1,972 | 2,681 | ||||||
Revisions | 1,549 | 16,087 | ||||||
Accretion expense | 14,162 | 10,642 | ||||||
Liabilities settled during the year | (7,353 | ) | (4,440 | ) | ||||
Asset retirement obligations, end of year | $ | 184,699 | $ | 171,866 | ||||
PENGROWTH ENERGY TRUST
2005 | 2004 | |||||||
U.S. dollar denominated debt: | ||||||||
U.S. $150 million senior unsecured notes at 4.93 percent due April 2010 | $ | 174,450 | $ | 180,300 | ||||
U.S. $50 million senior unsecured notes at 5.47 percent due April 2013 | 58,150 | 60,100 | ||||||
232,600 | 240,400 | |||||||
Pound sterling denominated £50 million unsecured notes at 5.46 percent due December 2015 | 100,489 | — | ||||||
Canadian dollar revolving credit borrowings | 35,000 | 105,000 | ||||||
$ | 368,089 | $ | 345,400 | |||||
2005 ANNUAL REPORT
2005 | 2004 | |||||||
Accumulated earnings | $ | 1,053,383 | $ | 727,057 | ||||
Accumulated distributions paid or declared | (2,096,030 | ) | (1,650,053 | ) | ||||
$ | (1,042,647 | ) | $ | (922,996 | ) | |||
Year Ended | Year Ended | |||||||||||||||
December 31, 2005 | December 31, 2004 | |||||||||||||||
Number of | Number of | |||||||||||||||
Trust Units Issued | Trust Units | Amount | Trust Units | Amount | ||||||||||||
Balance, beginning of period | 152,972,555 | $ | 2,383,284 | 123,873,651 | $ | 1,872,924 | ||||||||||
Issued for cash | — | — | 26,885,000 | 499,480 | ||||||||||||
Less: issue expenses | — | — | — | (26,287 | ) | |||||||||||
Issued for the Crispin acquisition (non-cash) (Note 4) | 4,225,313 | 87,960 | — | — | ||||||||||||
Issued for cash on exercise of trust unit options and rights | 1,512,211 | 21,818 | 1,294,838 | 20,251 | ||||||||||||
Issued for cash under Distribution Reinvestment Plan (DRIP) | 1,154,004 | 20,726 | 918,366 | 16,386 | ||||||||||||
Trust unit rights incentive plan (non-cash exercised) | — | 1,209 | — | 530 | ||||||||||||
Royalty units exchanged for trust units | — | — | 700 | — | ||||||||||||
Balance, end of period | 159,864,083 | $ | 2,514,997 | 152,972,555 | $ | 2,383,284 | ||||||||||
Year Ended | For the period from July 27, 2004 | |||||||||||||||
December 31, 2005 | to December 31, 2004 | |||||||||||||||
Number of | Number of | |||||||||||||||
Trust Units Issued | Trust Units | Amount | Trust Units | Amount | ||||||||||||
Balance, beginning of period | 76,792,759 | $ | 1,176,427 | — | $ | — | ||||||||||
Issued for the Crispin acquisition (non-cash) (Note 4) | 686,732 | 19,002 | — | — | ||||||||||||
Trust units converted | 45,182 | 692 | 76,792,759 | 1,176,427 | ||||||||||||
Balance, end of period | 77,524,673 | $ | 1,196,121 | 76,792,759 | $ | 1,176,427 | ||||||||||
PENGROWTH ENERGY TRUST
Year Ended | For the period from July 27, 2004 | |||||||||||||||
December 31, 2005 | to December 31, 2004 | |||||||||||||||
Number of | Number of | |||||||||||||||
Trust Units Issued | Trust Units | Amount | Trust Units | Amount | ||||||||||||
Balance, beginning of period | 76,106,471 | $ | 1,205,734 | — | $ | — | ||||||||||
Trust units converted | (9,824 | ) | (151 | ) | 59,000,129 | 903,854 | ||||||||||
Issued for cash | — | — | 15,985,000 | 298,920 | ||||||||||||
Less: issue expenses | — | — | — | (15,577 | ) | |||||||||||
Issued for the Crispin acquisition (non-cash) (Note 4) | 3,538,581 | 68,958 | — | — | ||||||||||||
Issued for cash on exercise of trust unit options and rights | 1,512,211 | 21,818 | 746,864 | 11,516 | ||||||||||||
Issued for cash under Distribution Reinvestment Plan (DRIP) | 1,154,004 | 20,726 | 374,478 | 6,750 | ||||||||||||
Trust unit rights incentive plan (non-cash exercised) | — | 1,209 | — | 271 | ||||||||||||
Balance, end of period | 82,301,443 | $ | 1,318,294 | 76,106,471 | $ | 1,205,734 | ||||||||||
Year Ended | Year Ended | |||||||||||||||
December 31, 2005 | December 31, 2004 | |||||||||||||||
Number of | Number of | |||||||||||||||
Trust Units Issued | Trust Units | Amount | Trust Units | Amount | ||||||||||||
Balance, beginning of year | 73,325 | $ | 1,123 | 123,873,651 | $ | 1,872,924 | ||||||||||
Issued for cash | — | — | 10,900,000 | 200,560 | ||||||||||||
Less: issue expenses | — | — | — | (10,710 | ) | |||||||||||
Issued for cash on exercise of trust unit options and rights | — | — | 547,974 | 8,735 | ||||||||||||
Issued for cash under Distribution Reinvestment Plan (DRIP) | — | — | 543,888 | 9,636 | ||||||||||||
Trust unit rights incentive plan (non-cash exercised) | — | — | — | 259 | ||||||||||||
Royalty units exchanged for trust units | — | — | 700 | — | ||||||||||||
Balance, prior to conversion | — | — | 135,866,213 | 2,081,404 | ||||||||||||
Converted to Class A or Class B trust units | (35,358 | ) | (541 | ) | (135,792,888 | ) | (2,080,281 | ) | ||||||||
Balance, end of year | 37,967 | $ | 582 | 73,325 | $ | 1,123 | ||||||||||
2005 ANNUAL REPORT
PENGROWTH ENERGY TRUST
2005 | 2004 | |||||||||
Balance, beginning of year | $ | 1,923 | $ | 189 | ||||||
Trust unit rights incentive plan (non-cash expensed) | 1,740 | 2,264 | ||||||||
Deferred entitlement trust units | 1,192 | — | ||||||||
Trust unit rights incentive plan (non-cash exercised) | (1,209 | ) | (530 | ) | ||||||
Balance, end of year | $ | 3,646 | $ | 1,923 | ||||||
2005 | 2004 | |||||||||||||||||||
Weighted | Weighted | |||||||||||||||||||
Number | Average | Number of | Average | |||||||||||||||||
of Options | Exercise Price | Options | Exercise Price | |||||||||||||||||
Outstanding at beginning of year | 845,374 | $ | 16.97 | 2,014,903 | $ | 17.47 | ||||||||||||||
Exercised | (558,307 | ) | $ | 16.74 | (838,789 | ) | $ | 16.82 | ||||||||||||
Expired | (27,750 | ) | $ | 18.63 | (325,200 | ) | $ | 20.44 | ||||||||||||
Cancelled | — | — | (5,540 | ) | $ | 16.53 | ||||||||||||||
Outstanding at year end | 259,317 | $ | 17.28 | 845,374 | $ | 16.97 | ||||||||||||||
Exercisable at year end | 259,317 | $ | 17.28 | 845,374 | $ | 16.97 | ||||||||||||||
2005 ANNUAL REPORT
Weighted Average | ||||||||||||
Number Outstanding | Remaining Contractual | Weighted Average | ||||||||||
Range of Exercise Prices | and Exercisable | Life (years) | Exercise Price | |||||||||
$12.00 to $14.99 | 30,193 | 2.9 | $ | 13.08 | ||||||||
$15.00 to $16.99 | 38,139 | 2.7 | $ | 15.05 | ||||||||
$17.00 to $17.99 | 82,772 | 2.4 | $ | 17.47 | ||||||||
$18.00 to $20.50 | 108,213 | 1.9 | $ | 19.09 | ||||||||
$12.00 to $20.50 | 259,317 | 2.3 | $ | 17.28 | ||||||||
2005 | 2004 | |||||||||||||||||||
Weighted | Weighted | |||||||||||||||||||
Number of | Average | Number of | Average | |||||||||||||||||
Rights | Exercise Price | Rights | Exercise Price | |||||||||||||||||
Outstanding at beginning of year | 2,011,451 | $ | 14.23 | 1,112,140 | $ | 12.20 | ||||||||||||||
Granted(1) | 606,575 | $ | 18.34 | 1,409,856 | $ | 17.35 | ||||||||||||||
Exercised | (953,904 | ) | $ | 12.81 | (456,049 | ) | $ | 13.47 | ||||||||||||
Cancelled | (222,385 | ) | $ | 16.19 | (54,496 | ) | $ | 14.19 | ||||||||||||
Outstanding at year end | 1,441,737 | $ | 14.85 | 2,011,451 | $ | 14.23 | ||||||||||||||
Exercisable at year end | 668,473 | $ | 13.73 | 1,037,078 | $ | 12.48 | ||||||||||||||
(1) | Weighted average exercise price of rights granted are based on the exercise price at the date of grant. |
PENGROWTH ENERGY TRUST
Rights Outstanding | Rights Exercisable | ||||||||||||||||||||
Weighted | |||||||||||||||||||||
Average | Weighted | Weighted | |||||||||||||||||||
Remaining | Average | Average | |||||||||||||||||||
Number | Contractual | Exercise | Number | Exercise | |||||||||||||||||
Range of Exercise Prices | Outstanding | Life (years) | Price | Exercisable | Price | ||||||||||||||||
$8.97 to $13.99 | 199,280 | 1.9 | $ | 9.03 | 199,280 | $ | 9.03 | ||||||||||||||
$14.00 to $15.99 | 549,620 | 3.1 | $ | 14.01 | 223,339 | $ | 14.01 | ||||||||||||||
$16.00 to $17.99 | 571,505 | 3.9 | $ | 16.89 | 206,942 | $ | 17.04 | ||||||||||||||
$18.00 to $20.99 | 121,332 | 4.8 | $ | 18.65 | 38,912 | $ | 18.68 | ||||||||||||||
$8.97 to $20.99 | 1,441,737 | �� | 3.1 | $ | 14.85 | 668,473 | $ | 13.73 | |||||||||||||
2004 | ||||
Net income | $ | 153,745 | ||
Compensation expense related to rights incentive options granted in 2002 | (1,067 | ) | ||
Pro forma net income | $ | 152,678 | ||
Pro forma net income per unit: | ||||
Basic | $ | 1.145 | ||
Diluted | $ | 1.139 | ||
2005 ANNUAL REPORT
Number of DEU’s | ||||
Outstanding, beginning of period | — | |||
Granted | 194,229 | |||
Cancelled | (26,258 | ) | ||
Deemed DRIP | 17,620 | |||
Outstanding, end of period | 185,591 | |||
PENGROWTH ENERGY TRUST
2005 ANNUAL REPORT
2005 | 2004 | |||||||||
Imputed interest on note payable (net of accumulated amortization of $2,859, 2004 — $1,587) | $ | 748 | $ | 2,020 | ||||||
U.S. debt issue costs (net of accumulated amortization of $816, 2004 — $510) | 1,325 | 1,631 | ||||||||
Deferred compensation expense (net of accumulated amortization of $2,143, 2004 — nil) | 2,141 | — | ||||||||
U.K. debt issue costs (net of accumulated amortization of $5) | 672 | — | ||||||||
$ | 4,886 | $ | 3,651 | |||||||
2005 | 2004 | |||||||||
Unrealized foreign exchange gain on translation of U.S. dollar denominated debt | $ | (7,800 | ) | $ | (18,900 | ) | ||||
Realized foreign exchange losses | 834 | 1,600 | ||||||||
$ | (6,966 | ) | $ | (17,300 | ) | |||||
Cash provided by (used for): | 2005 | 2004 | ||||||||
Accounts receivable | $ | (21,511 | ) | $ | (22,515 | ) | ||||
Inventory | 439 | 260 | ||||||||
Accounts payable and accrued liabilities | 29,953 | 17,225 | ||||||||
Due to Pengrowth Management Limited | 952 | 6,203 | ||||||||
$ | 9,833 | $ | 1,173 | |||||||
PENGROWTH ENERGY TRUST
Cash provided by: | 2005 | 2004 | ||||||||
Accounts payable for capital accruals | $ | 1,117 | $ | 2,169 | ||||||
2005 | 2004 | |||||||||
Cash payments made for taxes(1) | $ | 6,424 | $ | 4,729 | ||||||
Cash payments made for interest | $ | 21,779 | $ | 28,119 | ||||||
(1) | Capital and resource taxes |
2005 | 2004 | |||||||||
Income before taxes | $ | 344,875 | $ | 173,955 | ||||||
Combined federal and provincial tax rate | 37.6 | % | 38.6 | % | ||||||
Expected income tax | 129,673 | 67,147 | ||||||||
Net income of the Trust | (122,698 | ) | (59,346 | ) | ||||||
Resource allowance | (10,985 | ) | (8,807 | ) | ||||||
Non-deductible crown charges | 22,756 | 16,476 | ||||||||
Unrealized foreign exchange gain | (1,623 | ) | (3,648 | ) | ||||||
Attributed Canadian royalty income | (3,541 | ) | (3,113 | ) | ||||||
Effect of proposed tax changes | — | 3,850 | ||||||||
Future tax rate difference | (1,402 | ) | (1,585 | ) | ||||||
Change in valuation allowance | — | 3,035 | ||||||||
Other | 96 | 1,607 | ||||||||
Future income taxes | 12,276 | 15,616 | ||||||||
Capital taxes | 6,273 | 4,594 | ||||||||
$ | 18,549 | $ | 20,210 | |||||||
2005 ANNUAL REPORT
2005 | 2004 | |||||||||
Future income tax liabilities: | ||||||||||
Property, plant, equipment and other assets | $ | 114,256 | $ | 79,774 | ||||||
Unrealized foreign exchange gain | 9,689 | 8,378 | ||||||||
Other | 110 | — | ||||||||
124,055 | 88,152 | |||||||||
Future income tax assets: | ||||||||||
Attributed Canadian royalty income | (7,819 | ) | (4,418 | ) | ||||||
Contract liabilities | (6,124 | ) | (8,072 | ) | ||||||
Other | — | (34 | ) | |||||||
$ | 110,112 | $ | 75,628 | |||||||
PENGROWTH ENERGY TRUST
Remaining Term | Volume(bbl per day) | Reference Point | Price per bbl | |||||||||
Financial: | ||||||||||||
Jan 1, 2006 – Dec 31, 2006 | 4,000 | WTI (1) | $64.08 Cdn | |||||||||
2005 ANNUAL REPORT
Remaining Term | Volume (mmbtu per day) | Reference Point | Price per mmbtu | |||||||||
Financial: | ||||||||||||
Jan 1, 2006 – Mar 31, 2006 | 2,500 | NYMEX (1) | $14.56 Cdn | |||||||||
Jan 1, 2006 – Dec 31, 2006 | 2,500 | Transco Z6(1) | $10.63 Cdn | |||||||||
Jan 1, 2006 – Dec 31, 2006 | 2,370 | AECO | $8.03 Cdn | |||||||||
(1) | Associated Cdn$ / U.S.$ foreign exchange rate has been fixed. |
Remaining Term | Volume (mmbtu per day) | Price per mmbtu (1) | ||||||
2006 to 2009 | ||||||||
Jan 1, 2006 – Oct 31, 2006 | 3,886 | $2.23 Cdn | ||||||
Nov 1, 2006 – Oct 31, 2007 | 3,886 | $2.29 Cdn | ||||||
Nov 1, 2007 – Oct 31, 2008 | 3,886 | $2.34 Cdn | ||||||
Nov 1, 2008 – April 30, 2009 | 3,886 | $2.40 Cdn | ||||||
(1) | Reference price based on AECO |
As at December 31, 2005 | As at December 31, 2004 | |||||||||||||||||||
Net | Net | |||||||||||||||||||
Fair Value | Book Value | Fair Value | Book Value | |||||||||||||||||
Remediation Funds | $ | 9,071 | $ | 8,329 | $ | 8,366 | $ | 8,309 | ||||||||||||
U.S. dollar denominated debt | 220,187 | 232,600 | 238,726 | 240,400 | ||||||||||||||||
£ denominated debt | 101,257 | 100,489 | — | — | ||||||||||||||||
PENGROWTH ENERGY TRUST
2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | ||||||||||||||||||||||
Pipeline transportation | $ | 43,839 | $ | 38,197 | $ | 34,981 | $ | 29,813 | $ | 11,748 | $ | 53,525 | $ | 212,103 | ||||||||||||||
Capital expenditures | 33,323 | 7,098 | 294 | — | — | — | 40,715 | |||||||||||||||||||||
CO2 purchases | 5,119 | 4,357 | 4,198 | 4,232 | 4,267 | 18,728 | 40,901 | |||||||||||||||||||||
Other commitments | 3,132 | 3,096 | 3,950 | 3,610 | 3,377 | 32,779 | 49,944 | |||||||||||||||||||||
$ | 85,413 | $ | 52,748 | $ | 43,423 | $ | 37,665 | $ | 19,392 | $ | 105,032 | $ | 343,663 | |||||||||||||||
(1) | Contract prices for CO2 are denominated in U.S. dollars and have been translated at the year end foreign exchange rate. |
(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 ten percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. 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, 2005 and 2004, 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 write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion will differ in subsequent years. | ||
(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 trust unit based compensation plans. Under U.S. GAAP Pengrowth adopted the following: |
2005 ANNUAL REPORT
Year ended December 31, | 2004 | |||
Net income (loss) — U.S. GAAP, as reported | $ | 180,045 | ||
Compensation expense related to rights incentive options granted prior to January 1, 2003 | (1,067 | ) | ||
Pro forma net income — U.S. GAAP | $ | 178,978 | ||
Pro forma net income — U.S. GAAP per unit: | ||||
Basic | $ | 1.34 | ||
Diluted | $ | 1.34 | ||
(d) | Statement of Financial Accounting Standards (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. | |
(e) | 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, 2005, $18.4 million has been recorded as a current liability in respect of the fair value of financial crude oil and natural gas hedges outstanding at year end with a corresponding change in accumulated other comprehensive income. At December 31, 2004, $7.3 million has been recorded as a current asset in respect of the fair value of the financial crude oil and natural gas hedges outstanding at year end with a corresponding change in accumulated other comprehensive income. These amounts will be recognized against crude oil and natural gas sales over the remaining terms of the related hedges. |
PENGROWTH ENERGY TRUST
At December 31, 2005, $0.3 million 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 in net income. At December 31, 2004, the ineffective portion of crude oil and natural gas hedges outstanding at year end was not significant. | ||
At December 31, 2005, Pengrowth recorded a loss of $2.2 million relating to the foreign currency swap associated with the issuance of the £ denominated debt. As of February 14, 2006, Pengrowth had adequate documentation in place to account for the foreign currency contract as a hedge under U.S. GAAP. | ||
At December 31, 2004, there were no foreign exchange swaps outstanding. | ||
(f) | Under U.S. GAAP the Trust’s equity is classified as redeemable equity as the Trust units are redeemable at the option of the holder. The redemption price is equal to the lesser of 95 percent of the market trading price of the Class B trust units traded on the TSX for the 10 trading days after the trust units have been surrendered for redemption and the closing market price of the Class B trust units quoted on the TSX on the date the trust units have been surrendered for redemption. Prior to the reclassification of trust units into Class A or Class B trust units, the trust units were redeemable as described above except the redemption price was based on the market trading price of the original trust units. Trust units can be redeemed for cash to a maximum of $25,000 per month. Redemptions in excess of the cash limit must be satisfied by way of a distribution in Specie of a pro-rata share of royalty units and other assets, excluding facilities, pipelines or other assets associated with oil and natural gas production, which are held by the Trust at the time the trust units are to be redeemed. | |
(g) | Under U.S. standards, an entity that is subject to income tax in multiple jurisdictions is required to disclose income tax expense at each jurisdiction. Pengrowth is subject to tax at the federal and provincial level. The portion of income tax expense taxed at the federal level is $12.9 million (2004 – $14.8 million). The portion of income tax expense taxed at the provincial level is $5.7 million (2004 – $5.4 million). | |
(h) | In December 2004, the FASB issued SFAS 153 which deals with the accounting for the exchanges of non-monetary assets. SFAS 153 is an amendment of APB Opinion 29. APB Opinion 29 requires that exchanges of non-monetary assets should be measured based on the fair value of the assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception from using fair market value for non-monetary exchanges of similar productive assets and introduce a broader exception for exchanges of non-monetary assets that do not have commercial substance. SFAS 153 is effective for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Adopting the provisions of SFAS 153 is not expected to impact the U.S. GAAP financial statements. | |
In December 2004, the FASB issued SFAS 123R which deals with the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123R also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R is a revision of SFAS 123. SFAS 123R |
2005 ANNUAL REPORT
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, | 2005 | 2004 | ||||||||
Net income for the year, as reported | $ | 326,326 | $ | 153,745 | ||||||
Adjustments: | ||||||||||
Depletion and depreciation (a) | 24,723 | 26,000 | ||||||||
Unrealized gain (loss) on ineffective portion of oil and natural gas hedges (e) | (255 | ) | 300 | |||||||
Realized loss on foreign exchange contract (e) | (2,204 | ) | — | |||||||
Net income — U.S. GAAP | $ | 348,590 | $ | 180,045 | ||||||
Other comprehensive income: | ||||||||||
Realized gain on foreign exchange swap (d)(e) | — | (2,169 | ) | |||||||
Unrealized hedging gains (loss) (d)(e) | (25,470 | ) | 21,186 | |||||||
Comprehensive income — U.S. GAAP | $ | 323,120 | $ | 199,062 | ||||||
Net income — U.S. GAAP | ||||||||||
Basic | $ | 2.22 | $ | 1.35 | ||||||
Diluted | $ | 2.21 | $ | 1.34 | ||||||
PENGROWTH ENERGY TRUST
Stated in thousands of Canadian Dollars | As | Increase | ||||||||||
December 31, 2005 | Reported | (Decrease) | U.S. GAAP | |||||||||
Assets: | ||||||||||||
Capital assets (a) | $ | 2,067,988 | $ | (192,219 | ) | $ | 1,875,769 | |||||
$ | (192,219 | ) | ||||||||||
Liabilities | ||||||||||||
Accounts payable (e) | $ | 111,493 | $ | 255 | $ | 111,748 | ||||||
Current portion of unrealized hedging loss (e) | — | 18,153 | 18,153 | |||||||||
Current portion of unrealized foreign currency contract (e) | — | 2,204 | 2,204 | |||||||||
Unitholders’ equity (f): | ||||||||||||
Accumulated other comprehensive income (d)(e) | $ | — | $ | (18,153 | ) | $ | (18,153 | ) | ||||
Trust unitholders’ equity (a) | 1,475,996 | (194,678 | ) | 1,281,318 | ||||||||
$ | (192,219 | ) | ||||||||||
Stated in thousands of Canadian Dollars | As | Increase | ||||||||||
December 31, 2004 | Reported | (Decrease) | U.S. GAAP | |||||||||
Assets: | ||||||||||||
Current portion of unrealized hedging gain (e) | $ | — | $ | 7,317 | $ | 7,317 | ||||||
Capital assets (a) | 1,989,288 | (216,942 | ) | 1,772,346 | ||||||||
$ | (209,625 | ) | ||||||||||
Unitholders’ equity (f): | ||||||||||||
Accumulated other comprehensive income (d)(e) | $ | — | $ | 7,317 | $ | 7,317 | ||||||
Trust unitholders’ equity (a) | 1,462,211 | (216,942 | ) | 1,245,269 | ||||||||
$ | (209,625 | ) | ||||||||||
As at December 31, | 2005 | 2004 | ||||||
Trade | $ | 103,619 | $ | 77,778 | ||||
Prepaids | 20,230 | 15,378 | ||||||
Other | 3,545 | 11,072 | ||||||
$ | 127,394 | $ | 104,228 | |||||
As at December 31, | 2005 | 2004 | ||||||
Accounts payable | $ | 50,756 | $ | 37,588 | ||||
Accrued liabilities | 60,737 | 42,835 | ||||||
$ | 111,493 | $ | 80,423 | |||||
2005 ANNUAL REPORT
FINANCIAL RESULTS (INCLUDED ON PAGES 115 THROUGH 119 OF THE
PENGROWTH ENERGY TRUST 2005 ANNUAL REPORT)
(Stated in thousands of dollars) | |||||||||||||||||||||
As at December 31 | 2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
ASSETS | |||||||||||||||||||||
Current assets | |||||||||||||||||||||
Cash and term deposits | — | — | 64,154 | 8,292 | 3,797 | ||||||||||||||||
Other current assets | 127,394 | 104,667 | 66,269 | 44,633 | 30,546 | ||||||||||||||||
127,394 | 104,667 | 130,423 | 52,925 | 34,343 | |||||||||||||||||
Goodwill | 182,835 | 170,619 | — | — | — | ||||||||||||||||
Property, plant and equipment | 2,067,988 | 1,989,288 | 1,530,359 | 1,493,047 | 1,229,395 | ||||||||||||||||
Other long term assets | 13,215 | 11,960 | 12,936 | 6,679 | 6,470 | ||||||||||||||||
2,391,432 | 2,276,534 | 1,673,718 | 1,552,651 | 1,270,208 | |||||||||||||||||
LIABILITIES AND UNITHOLDERS’ EQUITY | |||||||||||||||||||||
Current liabilities | |||||||||||||||||||||
Bank indebtedness | 14,567 | 4,214 | — | — | — | ||||||||||||||||
Other current liabilities | 225,032 | 178,999 | 117,457 | 89,493 | 54,089 | ||||||||||||||||
239,599 | 183,213 | 117,457 | 89,493 | 54,089 | |||||||||||||||||
Long term debt | 368,089 | 345,400 | 259,300 | 316,501 | 345,456 | ||||||||||||||||
Other long term liabilities | 307,748 | 285,710 | 137,528 | 73,493 | 42,123 | ||||||||||||||||
Trust unitholders’ equity | |||||||||||||||||||||
Trust unitholders’ capital | 2,514,997 | 2,383,284 | 1,872,924 | 1,662,726 | 1,280,599 | ||||||||||||||||
Contributed surplus | 3,646 | 1,923 | 189 | — | — | ||||||||||||||||
Deficit | (1 ,042,647 | ) | (922,996 | ) | (713,680 | ) | (589,562 | ) | (452,059 | ) | |||||||||||
1,475,996 | 1,462,211 | 1,159,433 | 1,073,164 | 828,540 | |||||||||||||||||
2,391,432 | 2,276,534 | 1,673,718 | 1,552,651 | 1,270,208 | |||||||||||||||||
2005 ANNUAL REPORT
(Stated in thousands of dollars) | ||||||||||||||||||||
Years ended December 31 | 2005 | 2004 | 2003 | 2002 | 2001 | |||||||||||||||
REVENUES | ||||||||||||||||||||
Oil and gas sales(1) | 1,151,510 | 815,751 | 702,732 | 490,472 | 479,845 | |||||||||||||||
Processing and other income | 15,091 | 12,390 | 9,726 | 6,936 | 7,071 | |||||||||||||||
Royalties, net of incentives(1) | (213,863 | ) | (160,351 | ) | (126,617 | ) | (88,777 | ) | (81,876 | ) | ||||||||||
952,738 | 667,790 | 585,841 | 408,631 | 405,040 | ||||||||||||||||
Interest and other income | 2,596 | 1,770 | 840 | 274 | 1,348 | |||||||||||||||
Net revenues | 955,334 | 669,560 | 586,681 | 408,905 | 406,388 | |||||||||||||||
EXPENSES | ||||||||||||||||||||
Operating | 218,115 | 159,742 | 149,032 | 129,802 | 104,943 | |||||||||||||||
Transportation | 7,891 | 8,274 | 8,225 | – | – | |||||||||||||||
Amortization of injectants for miscible floods | 24,393 | 19,669 | 32,541 | 44,330 | 47,448 | |||||||||||||||
Interest | 21,642 | 29,924 | 18,153 | 15,213 | 18,806 | |||||||||||||||
General and administrative | 30,272 | 24,448 | 15,997 | 10,992 | 7,467 | |||||||||||||||
Management fee | 15,961 | 12,874 | 10,181 | 6,567 | 7,120 | |||||||||||||||
Foreign exchange loss (gain) | (6,966 | ) | (17,300 | ) | (29,911 | ) | 182 | 0 | ||||||||||||
Depletion and depreciation | 284,989 | 247,332 | 185,270 | 140,775 | 126,409 | |||||||||||||||
Accretion | 14,162 | 10,642 | 6,039 | 3,566 | 3,293 | |||||||||||||||
610,459 | 495,605 | 395,527 | 351,427 | 315,486 | ||||||||||||||||
Income before taxes | 344,875 | 173,955 | 191,154 | 57,478 | 90,902 | |||||||||||||||
Income tax expense | ||||||||||||||||||||
Capital | 6,273 | 4,594 | 1,857 | 523 | 2,717 | |||||||||||||||
Future | 12,276 | 15,616 | – | – | – | |||||||||||||||
18,549 | 20,210 | 1,857 | 523 | 2,717 | ||||||||||||||||
NET INCOME | 326,326 | 153,745 | 189,297 | 56,955 | 88,185 | |||||||||||||||
Deficit, beginning of year | (922,996 | ) | (713,680 | ) | (589,562 | ) | (452,059 | ) | (324,457 | ) | ||||||||||
Distributions paid or declared | (445,977 | ) | (363,061 | ) | (313,415 | ) | (194,458 | ) | (215,787 | ) | ||||||||||
Deficit, end of year | ( 1,042,647 | ) | (922,996 | ) | (713,680 | ) | (589,562 | ) | (452,059 | ) | ||||||||||
Net income per trust unit | ||||||||||||||||||||
Basic | 2.08 | 1.15 | 1.63 | 0.63 | 1.24 | |||||||||||||||
Diluted | 2.07 | 1.15 | 1.63 | 0.63 | 1.24 | |||||||||||||||
(1)Prior years restated to conform to presentation adopted in current year. |
PENGROWTH ENERGY TRUST
(Stated in thousands of dollars) | ||||||||||||||||||||
Years ended December 31 | 2005 | 2004 | 2003 | 2002 | 2001 | |||||||||||||||
CASH PROVIDED BY (USED FOR): | ||||||||||||||||||||
Operating | ||||||||||||||||||||
Net income | 326,326 | 153,745 | 189,297 | 56,955 | 88,185 | |||||||||||||||
Depletion and depreciation | 284,989 | 247,332 | 185,270 | 140,775 | 126,409 | |||||||||||||||
Accretion | 14,162 | 10,642 | 6,039 | 3,566 | 3,293 | |||||||||||||||
Future income taxes | 12,276 | 15,616 | — | — | — | |||||||||||||||
Amortization of injectants | 24,393 | 19,669 | 32,541 | 44,330 | 47,448 | |||||||||||||||
Purchase of injectants | (34,658 | ) | (20,415 | ) | (23,037 | ) | (15,107 | ) | (56,352 | ) | ||||||||||
Other non-cash items | (19,251 | ) | (23,595 | ) | (33,696 | ) | (1,783 | ) | (1,223 | ) | ||||||||||
Changes in non-cash operating working capital | 9,833 | 1,173 | (9,863 | ) | 120 | (2,919 | ) | |||||||||||||
618,070 | 404,167 | 346,551 | 228,856 | 204,841 | ||||||||||||||||
Financing | ||||||||||||||||||||
Distributions | (436,450 | ) | (344,744 | ) | (306,591 | ) | (171,350 | ) | (241,590 | ) | ||||||||||
Changes in long term debt and note payable | (4,970 | ) | 95,000 | 15,132 | (28,955 | ) | 58,080 | |||||||||||||
Proceeds from issue of trust units | 42,544 | 509,830 | 210,198 | 382,127 | 305,875 | |||||||||||||||
(398,876 | ) | 260,086 | (81,261 | ) | 181,822 | 122,365 | ||||||||||||||
Investing | ||||||||||||||||||||
Expenditures on property acquisitions | (92,568 | ) | (572,980 | ) | (122,964 | ) | (391,761 | ) | (280,058 | ) | ||||||||||
Expenditures on property, plant and equipment | (175,693 | ) | (161,141 | ) | (85,718 | ) | (55,631 | ) | (74,026 | ) | ||||||||||
Other items | 38,714 | 1,500 | (746 | ) | 41,209 | 26,142 | ||||||||||||||
(229,547 | ) | (732,621 | ) | (209,428 | ) | (406,183 | ) | (327,942 | ) | |||||||||||
Change in cash and term deposits | (10,353 | ) | (68,368 | ) | 55,862 | 4,495 | (736 | ) | ||||||||||||
Cash and term deposits (bank indebtedness) at beginning of year | (4,214 | ) | 64,154 | 8,292 | 3,797 | 4,533 | ||||||||||||||
Cash and term deposits (bank indebtedness) at year end | (14,567 | ) | (4,214 | ) | 64,154 | 8,292 | 3,797 | |||||||||||||
2005 ANNUAL REPORT
Years ended December 31 | 2005 | 2004 | 2003 | 2002 | 2001 | |||||||||||||||
PRODUCTION | ||||||||||||||||||||
Crude Oil (bbl per day) | 20,799 | 20,817 | 23,337 | 19,914 | 19,726 | |||||||||||||||
Heavy Oil (bbl per day) | 5,623 | 3,558 | — | — | — | |||||||||||||||
Natural Gas (mcf per day) | 161,056 | 144,277 | 119,842 | 111,713 | 91,764 | |||||||||||||||
Natural gas liquids (bbl per day) | 6,093 | 5,281 | 5,722 | 5,252 | 5,258 | |||||||||||||||
Total (boe per day) | 59,357 | 53,702 | 49,033 | 43,785 | 40,320 | |||||||||||||||
Annual (mmboe) | 21.7 | 19.7 | 17.9 | 16.0 | 14.7 | |||||||||||||||
% natural gas | 45 | 45 | 41 | 43 | 38 | |||||||||||||||
Production per weighted average trust unit outstanding (boe) | 0.14 | 0.15 | 0.15 | 0.18 | 0.21 | |||||||||||||||
BENCHMARK PRICES | ||||||||||||||||||||
WTI (U.S. $ per bbl) | $ | 56.70 | $ | 41.47 | $ | 30.99 | $ | 26.08 | $ | 25.90 | ||||||||||
NYMEX (U.S. $ per mmbtu) | $ | 8.62 | $ | 6.16 | $ | 5.39 | $ | 3.22 | $ | 4.27 | ||||||||||
AECO (Cdn $ per mcf) | $ | 8.48 | $ | 6.79 | $ | 6.70 | $ | 4.07 | $ | 6.30 | ||||||||||
Currency (U.S. $ per Cdn $) | $ | 0.83 | $ | 0.77 | $ | 0.71 | $ | 0.64 | $ | 0.65 | ||||||||||
AVERAGE REALIZED PRICES | ||||||||||||||||||||
Oil ($ per bbl) | $ | 58.59 | $ | 43.21 | $ | 40.85 | $ | 38.06 | $ | 37.26 | ||||||||||
Heavy Oil ($ per bbl) | $ | 33.32 | $ | 32.45 | n/a | n/a | n/a | |||||||||||||
Natural Gas ( $ per mcf) | $ | 8.76 | $ | 6.80 | $ | 6.35 | $ | 3.85 | $ | 4.48 | ||||||||||
Natural gas liquids ($ per bbl) | $ | 54.22 | $ | 42.21 | $ | 35.54 | $ | 28.11 | $ | 30.68 | ||||||||||
Average price per boe(1) | $ | 53.02 | $ | 41.33 | $ | 39.12 | $ | 30.50 | $ | 32.47 | ||||||||||
AVERAGE NETBACK | ||||||||||||||||||||
Light oil netback ( $ per bbl) | $ | 35.01 | $ | 24.38 | $ | 23.40 | n/a | n/a | ||||||||||||
Heavy oil netback ($ per bbl) | $ | 13.50 | $ | 17.73 | n/a | n/a | n/a | |||||||||||||
Natural gas netback ( $ per mcf) | $ | 5.95 | $ | 4.47 | $ | 3.89 | n/a | n/a | ||||||||||||
NGL netback ( $ per bbl) | $ | 27.52 | $ | 18.74 | $ | 13.09 | n/a | n/a | ||||||||||||
Operating netback ($ per boe) | $ | 32.54 | $ | 24.51 | $ | 22.17 | $ | 14.70 | $ | 17.25 | ||||||||||
Property acquisitions ($ millions) | $ | 175.1 | $ | 569.7 | $ | 126.5 | $ | 389.3 | $ | 277.1 | ||||||||||
Capital expenditures ($ millions) | $ | 175.7 | $ | 161.1 | $ | 85.7 | $ | 55.6 | $ | 74.0 | ||||||||||
Reserves (proved plus probable) | ||||||||||||||||||||
Reserves acquired in the year (mmboe) | 16.7 | 47.9 | n/a | 37.7 | 48.4 | |||||||||||||||
Reserves at year end (mmboe) | 219.4 | 218.6 | 184.4 | 214.8 | 210.5 | |||||||||||||||
Acquisition cost per boe(1) | $ | 10.49 | $ | 11.89 | n/a | $ | 10.33 | $ | 5.72 | |||||||||||
Reserves per year end trust units outstanding | 1.37 | 1.43 | 1.49 | 1.94 | 2.56 | |||||||||||||||
(1)Prior years restated to conform to presentation adopted in current year. |
PENGROWTH ENERGY TRUST
(Stated in thousands of dollars, except per trust unit amounts) | ||||||||||||||||||||
Years ended December 31 | 2005 | 2004 | 2003 | 2002 | 2001 | |||||||||||||||
Expenses(per boe) | ||||||||||||||||||||
Royalties | $ | 9.87 | $ | 8.16 | $ | 7.07 | $ | 5.56 | $ | 5.56 | ||||||||||
Operating | $ | 10.07 | $ | 8.13 | $ | 8.33 | $ | 8.12 | $ | 7.13 | ||||||||||
Transportation | $ | 0.36 | $ | 0.42 | $ | 0.46 | $ | — | $ | — | ||||||||||
Amortization of injectants for miscible floods | $ | 1.13 | $ | 1.00 | $ | 1.82 | $ | 2.77 | $ | 3.22 | ||||||||||
Interest | $ | 1.00 | $ | 1.52 | $ | 1.01 | $ | 0.95 | $ | 1.28 | ||||||||||
General and administrative | $ | 1.40 | $ | 1.24 | $ | 0.89 | $ | 0.69 | $ | 0.51 | ||||||||||
Management fee | $ | 0.74 | $ | 0.66 | $ | 0.57 | $ | 0.41 | $ | 0.48 | ||||||||||
Depletion and depreciation | $ | 13.15 | $ | 12.58 | $ | 10.35 | $ | 8.81 | $ | 8.59 | ||||||||||
Accretion | $ | 0.65 | $ | 0.54 | $ | 0.34 | $ | 0.22 | $ | 0.22 | ||||||||||
Net income | $ | 326,326 | $ | 153,745 | $ | 189,297 | $ | 56,955 | $ | 88,185 | ||||||||||
Net income per trust unit | $ | 2.08 | $ | 1.15 | $ | 1.63 | $ | 0.63 | $ | 1.24 | ||||||||||
Distributable Cash | ||||||||||||||||||||
Cash Generated from Operations | $ | 618,070 | $ | 404,167 | $ | 346,551 | $ | 228,856 | $ | 204,841 | ||||||||||
Cash Generated from Operations per trust unit | $ | 3.93 | $ | 3.03 | $ | 2.99 | $ | 2.55 | $ | 2.89 | ||||||||||
Distributable cash(1) | $ | 619,739 | $ | 401,178 | $ | 345,911 | $ | 199,480 | $ | 215,787 | ||||||||||
Distributable cash per trust unit(1) | $ | 3.94 | $ | 3.01 | $ | 2.98 | $ | 2.22 | $ | 3.04 | ||||||||||
Actual distributions paid or declared | $ | 445,977 | $ | 363,061 | $ | 313,415 | $ | 194,458 | $ | 215,787 | ||||||||||
Actual distributions paid or declared per trust unit | $ | 2.82 | $ | 2.63 | $ | 2.68 | $ | 2.07 | $ | 3.01 | ||||||||||
Payout Ratio (%) | 72 | 90 | 90 | 85 | 105 | |||||||||||||||
Number of trust units outstanding | ||||||||||||||||||||
Weighted average | 157,127 | 133,395 | 115,912 | 89,923 | 70,911 | |||||||||||||||
Total at year end | 159,864 | 152,973 | 123,874 | 110,562 | 82,240 | |||||||||||||||
Total assets | $ | 2,391,432 | $ | 2,276,534 | $ | 1,673,718 | $ | 1,552,651 | $ | 1,270,208 | ||||||||||
Total assets per trust unit | $ | 14.96 | $ | 14.88 | $ | 13.51 | $ | 14.04 | $ | 15.45 | ||||||||||
Long term debt | $ | 368,089 | $ | 345,400 | $ | 259,300 | $ | 316,501 | $ | 345,456 | ||||||||||
Long term debt per trust unit | $ | 2.30 | $ | 2.26 | $ | 2.09 | $ | 2.86 | $ | 4.20 | ||||||||||
Unitholders’ equity | $ | 1,475,996 | $ | 1,462,211 | $ | 1,159,433 | $ | 1,073,164 | $ | 828,540 | ||||||||||
Unitholders’ equity per trust unit | $ | 9.23 | $ | 9.56 | $ | 9.36 | $ | 9.71 | $ | 10.07 | ||||||||||
Net asset value at 10% | $ | 2,834,663 | $ | 1,708,012 | $ | 1,124,433 | $ | 1,239,322 | $ | 914,970 | ||||||||||
Net asset value per trust unit | $ | 17.73 | $ | 11.17 | $ | 9.08 | $ | 11.21 | $ | 11.13 | ||||||||||
Capitalization highlights | ||||||||||||||||||||
Net debt (net of working capital) | $ | 480,294 | $ | 443,946 | $ | 281,334 | $ | 353,069 | $ | 365,202 | ||||||||||
Unitholders’ equity | $ | 1,475,996 | $ | 1,462,211 | $ | 1,159,433 | $ | 1,073,164 | $ | 828,540 | ||||||||||
Total book capitalization | $ | 1,956,290 | $ | 1,906,157 | $ | 1,440,767 | $ | 1,426,233 | $ | 1,193,742 | ||||||||||
Equity Market capitalization | $ | 3,989,939 | $ | 3,323,770 | $ | 2,632,315 | $ | 1,628,583 | $ | 1,169,454 | ||||||||||
Enterprise value | $ | 4,358,028 | $ | 3,669,170 | $ | 2,891,615 | $ | 1,945,084 | $ | 1,514,910 | ||||||||||
Return on average equity (%) | 22.2 | 11.7 | 17.0 | 6.0 | 11.9 | |||||||||||||||
Cash flow return on average equity (%) | 30.3 | 27.7 | 28.1 | 20.5 | 29.2 | |||||||||||||||
Average cost of debt capital (%)(1) | 4.6 | 5.1 | 5.1 | 4.6 | 5.2 | |||||||||||||||
(1)Prior years restated to conform to presentation adopted in current year. |
2005 ANNUAL REPORT
PENGROWTH ENERGY TRUST 2005 ANNUAL REPORT)
Back row:
Michael Parrett
Terry Poole
Kirby Hedrick
Stan Wong
John Zaozirny
Jim Kinnear
Tom Cumming
PENGROWTH ENERGY TRUST
2005 ANNUAL REPORT
PENGROWTH ENERGY TRUST
2005 ANNUAL REPORT
PENGROWTH ENERGY TRUST
2005 ANNUAL REPORT
SFAS NO. 69 — “DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES”.
2005 | 2004 | |||||||
(thousands of dollars) | ||||||||
Revenue | ||||||||
Sales | $ | 952,738 | $ | 667,790 | ||||
Deduct | ||||||||
Production costs | 208,140 | 152,400 | ||||||
Transportation costs | 7,891 | 8,274 | ||||||
Amortization of injectant costs | 24,393 | 19,669 | ||||||
Technical support and other | 9,975 | 7,342 | ||||||
Depletion, depreciation and amortization | 260,266 | 221,332 | ||||||
Results of operations from producing activities | $ | 442,073 | $ | 258,773 | ||||
1. | The costs in this schedule exclude corporate overhead, interest expense and other operating costs which are not directly related to producing activities. |
2005 | 2004 | |||||||
(thousands of dollars) | ||||||||
Property Acquisition Costs | ||||||||
Proved | $ | 208,424 | $ | 512,348 | ||||
Unproved | 18,697 | 12,766 | ||||||
Development Costs | 169,314 | 161,141 | ||||||
Injectant Costs | 34,658 | 20,415 | ||||||
$ | 431,093 | $ | 706,670 | |||||
2005 | 2004 | |||||||
(thousands of dollars) | ||||||||
Oil and gas properties | $ | 3,375,412 | $ | 3,011,723 | ||||
Less accumulated depletion, depreciation and amortization | (1,499,643 | ) | (1,239,377 | ) | ||||
Net capitalized costs | $ | 1,875,769 | $ | 1,772,346 | ||||
Crude Oil | ||||||||
and Natural | Natural | |||||||
Gas Liquids | Gas | |||||||
MMbbls | Bcf | |||||||
NET PROVED DEVELOPED AND UNDEVELOPED RESERVES AFTER ROYALTIES | ||||||||
End of year 2003 | 77.3 | 271.4 | ||||||
Revision of previous estimates | 1.7 | 16.0 | ||||||
Purchase of reserves in place | 17.0 | 97.1 | ||||||
Sales of reserves in place | — | — | ||||||
Discoveries and extensions | 0.1 | 1.8 | ||||||
Production | (8.8 | ) | (42.7 | ) | ||||
End of year 2004 | 87.3 | 343.6 | ||||||
Revision of previous estimates | 3.1 | 11.6 | ||||||
Purchase of reserves in place | 8.0 | 15.2 | ||||||
Sales of reserves in place | (1.2 | ) | (3.9 | ) | ||||
Discoveries and extensions | 0.6 | 15.6 | ||||||
Production | (9.6 | ) | (48.6 | ) | ||||
End of year 2005 | 88.2 | 333.5 | ||||||
NET PROVED DEVELOPED RESERVES AFTER ROYALTIES | ||||||||
End of year 2003 | 60.6 | 219.9 | ||||||
End of year 2004 | 70.5 | 305.7 | ||||||
End of year 2005 | 70.4 | 309.3 |
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. |
2005 | 2004 | |||||||
(millions of dollars) | ||||||||
Future cash inflows | $ | 8,591 | $ | 5,869 | ||||
Future costs | ||||||||
Future production and development costs | (2,892 | ) | (2,494 | ) | ||||
Future net cash flows | 5,699 | 3,375 | ||||||
Deduct: 10% annual discount factor | (2,355 | ) | (1,383 | ) | ||||
Standardized measure of discounted future net cash flows | $ | 3,344 | $ | 1,992 | ||||
2005 | 2004(2) | |||||||
(millions of dollars) | ||||||||
Future discounted net cash flows at beginning of year | $ | 1,992 | $ | 1,604 | ||||
Sales and transfer, net of production costs | (706 | ) | (480 | ) | ||||
Net change in sales and transfer prices, net of production costs | 1,450 | 176 | ||||||
Development costs during the year | 169 | 161 | ||||||
Change in future development costs | (139 | ) | (166 | ) | ||||
Changes due to extensions and discoveries | 74 | 5 | ||||||
Changes due to revisions (including infill drilling and improved recovery) | 109 | 58 | ||||||
Accretion of discount | 199 | 160 | ||||||
Sales of reserves in place | (26 | ) | — | |||||
Purchase of reserves in place | 196 | 459 | ||||||
Changes in timing of future net cash flows and other | 26 | 15 | ||||||
End of Year | $ | 3,344 | $ | 1,992 | ||||
Notes: | ||
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. | |
2. | Certain prior year amounts have been restated to conform to presentation adopted in current year. |