o | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934. |
þ | ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934 |
(Province or other jurisdiction of incorporation or organization)
1311 | None | |
(Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification Number) |
Calgary, Alberta Canada T2P 0B4
(403) 233-0224
(Address and telephone number of Registrant’s principal executive offices)
111-8th Avenue, New York, New York 10011
(212) 894-8940
of agent for service in the United States)
Brad D. Markel Bennett Jones LLP 4500 Bankers Hall East 855 — 2nd Street SW Calgary, Alberta T2P 4K7 Canada (403) 298-3100 | Edwin S. Maynard Paul, Weiss, Rifkind, Wharton & Garrison LLP 1285 Avenue of the Americas New York, New York 10019-6064 USA (212) 373-3000 |
Title of each class | Name of each exchange on which registered | |
Trust Units | New York Stock Exchange |
Appendix | Documents | |
A | Pengrowth Energy Trust Annual Information Form for the year ended December 31, 2007. | |
B | Management’s Discussion and Analysis. | |
C | Consolidated Financial Statements of Pengrowth Energy Trust, including Management’s Report to Unitholders, the Auditors’ Reports and note 23 thereof which includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles. | |
D | Comments by Auditors for U.S. Readers on Canada — U.S. Reporting Differences. | |
E | Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”. | |
F | Pengrowth Energy Trust Code of Business Conduct and Ethics dated February 19, 2008. |
Date: March 19, 2008 | PENGROWTH ENERGY TRUST by its Administrator PENGROWTH CORPORATION | |||
By: | /s/ James S. Kinnear | |||
James S. Kinnear | ||||
Chairman, President and Chief Executive Officer | ||||
ENDED DECEMBER 31, 2007
For the year ended December 31, 2007
GLOSSARY OF TERMS AND ABBREVIATIONS | 1 | |||
Corporate | 1 | |||
Engineering | 2 | |||
Abbreviations | 3 | |||
CONVERSION | 4 | |||
PRESENTATION OF OUR FINANCIAL INFORMATION | 5 | |||
PRESENTATION OF OUR RESERVE INFORMATION | 5 | |||
FORWARD-LOOKING STATEMENTS | 5 | |||
PENGROWTH ENERGY TRUST | 7 | |||
Introduction | 7 | |||
The Trust | 7 | |||
The Corporation | 7 | |||
The Trust’s Subsidiaries | 7 | |||
The Corporation’s Subsidiaries | 8 | |||
The Manager | 8 | |||
Intercorporate Relationships | 8 | |||
Business Strategy and Strengths | 9 | |||
SIFT Legislation Considerations | 11 | |||
GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST | 12 | |||
Recent Developments | 12 | |||
Historical Developments | 16 | |||
Trends | 19 | |||
PENGROWTH MANAGEMENT LIMITED | 20 | |||
Business | 20 | |||
Management Agreement | 20 | |||
Bonus Pool | 21 | |||
Management Agreement Second Term | 22 | |||
PENGROWTH – OPERATIONAL INFORMATION | 23 | |||
Principle Properties | 23 | |||
Light Oil Properties | 24 | |||
Heavy Oil Properties | 27 | |||
Conventional Gas Properties | 28 | |||
Shallow Gas Properties | 31 | |||
Offshore Gas Properties | 33 | |||
Statement of Oil and Gas Reserves and Reserves Data | 35 | |||
Additional Information Relating to Reserves Data | 45 | |||
Future Development Costs | 47 | |||
Finding, Development and Acquisition Costs | 47 | |||
Future Development Capital | 48 | |||
Other Oil and Gas Information | 49 | |||
Additional Information Concerning Abandonment & Reclamation Costs | 50 | |||
Costs Incurred | 51 | |||
Exploration and Development Activities | 51 | |||
Production Estimates | 51 | |||
Production History (Netback) | 52 | |||
Replacement of Properties | 52 | |||
TRUST UNITS | 53 | |||
The Trust Indenture | 53 | |||
The Trustee | 54 | |||
Stock Exchange Listings | 54 | |||
Ownership Restrictions | 54 | |||
Redemption Right | 54 |
Conversion Rights | 55 | |||
Voting at Meetings of Unitholders | 55 | |||
Voting at Meetings of Corporation | 55 | |||
Termination of the Trust | 55 | |||
Unitholder Limited Liability | 56 | |||
THE ROYALTY INDENTURE | 57 | |||
Royalty Units | 57 | |||
The Royalty | 57 | |||
The Trustee | 58 | |||
EXCHANGEABLE SHARES | 58 | |||
DISTRIBUTIONS | 59 | |||
General | 59 | |||
Historical Distributions | 59 | |||
Restrictions on Distributions | 60 | |||
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS | 64 | |||
Taxation of Unitholders Resident in Canada | 65 | |||
Taxation of Unitholders who are Non-Residents of Canada | 66 | |||
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS | 67 | |||
Classification of Pengrowth Energy Trust as a Partnership | 68 | |||
Possible Classification as a Corporation; PFIC Rules | 68 | |||
Consequences of Possible PFIC Classification | 69 | |||
Tax Consequences of Trust Unit Ownership | 70 | |||
Tax Treatment of Trust Operations | 71 | |||
Disposition of Trust Units | 73 | |||
Disposition of Trust Units by Redemption | 74 | |||
Uniformity of Trust Units | 75 | |||
Tax-Exempt Organizations | 75 | |||
Administrative Matters | 75 | |||
Reportable Transactions | 76 | |||
Foreign Partnership Reporting | 76 | |||
INDUSTRY CONDITIONS | 76 | |||
Government Regulation | 76 | |||
Pricing and Marketing — Oil | 76 | |||
Pricing and Marketing — Natural Gas | 77 | |||
Pricing and Marketing — Natural Gas Liquids | 77 | |||
Environmental Regulation | 78 | |||
RISK FACTORS | 80 | |||
MARKET FOR SECURITIES | 93 | |||
DIRECTORS AND OFFICERS | 94 | |||
Directors and Officers of the Manager | 94 | |||
Principal Holders of Shares of the Manager | 94 | |||
Directors and Officers of the Corporation | 94 | |||
Corporate Cease Trade Orders or Bankruptcies | 96 | |||
Personal Bankruptcies | 97 | |||
Penalties or Sanctions | 97 | |||
AUDIT COMMITTEE | 97 | |||
Principal Accountant Fees and Services | 98 | |||
Pre-approval Policies and Procedures | 98 |
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CONFLICTS OF INTEREST | 99 | |||
LEGAL PROCEEDINGS | 99 | |||
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS | 99 | |||
INTERESTS OF EXPERTS | 100 | |||
AUDITORS, TRANSFER AGENT AND REGISTRAR | 100 | |||
MATERIAL CONTRACTS | 100 | |||
CODE OF ETHICS | 101 | |||
OFF-BALANCE SHEET ARRANGEMENTS | 101 | |||
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE | 101 | |||
ADDITIONAL INFORMATION | 102 |
Appendix B — Report on Management and Directors on Oil and Gas Disclosure on Form 51-101F3
Appendix C — Audit Committee Terms of Reference
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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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• | Acquisitions should be accretive on a per Trust Unit basis based upon current forecast parameters. In determining whether an acquisition is accretive, we examine the profile of production, operating costs, capital costs, abandonment expenses and other key variables and compare that with our existing asset base to understand the impact over time in terms of production, reserves and distributions on a per Trust Unit basis. | ||
• | 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. | ||
• | Properties to be acquired should be high quality, relatively long life and proven producing properties. Pengrowth 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 | 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 must be based on an independent engineering report except for properties where the purchase price is less than $5 million. |
• | Development investments should provide a high rate of return and provide production within a short period of time, or be necessary to maintain existing production operations. Pengrowth prioritizes its development investments based on: |
o | rate of return; | ||
o | timing of production; | ||
o | potential for continued development; and | ||
o | those investments necessary to maintain existing facilities and wells. |
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Planned Capital Expenditures | ($ millions) | (% of Total) | ||||||
Drilling and Completions | $ | 281 | 80 | % | ||||
Plant and Facilities | $ | 44 | 12 | % | ||||
Land and Seismic | $ | 25 | 7 | % | ||||
Other (e.g., CO2 Pilot) | $ | 5 | 1 | % | ||||
Total Development Capital | $ | 355 | 100 | % | ||||
Long Term Investments (Lindbergh, Building, IT) | $ | 32 | ||||||
Total Capital | $ | 387 | ||||||
Average Daily Production Volume (boepd) | 80,000 - 82,000(1) | |||||||
Operating Costs (per boe) | $ | 13.20 | (2) | |||||
General and Administrative Costs (per boe) | $ | 2.20 | (3) | |||||
(1) | The 2008 estimate excludes potential additions through acquisitions. | |
(2) | Assuming production targets for 2008 are achieved. | |
(3) | Includes management fees of approximately $0.40 per boe. |
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• | two distinct three-year terms with a declining fee structure in the second three year term; | ||
• | a base fee determined on a sliding scale: |
o | in the first three year contract term: |
§ | two percent of the first $200 million of Income; and | ||
§ | one 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. |
For these purposes, “Income” means the aggregate of net production revenue of the Corporation and any other income earned from permitted investments of the Trust (excluding interest on cash or near-cash deposits or similar investments). |
• | a performance based fee based on total returns received by Unitholders which essentially compensates the Manager for total annual returns which average in excess of eight percent per annum over a three year period; | ||
• | 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; |
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• | 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 Royalty Unitholders. |
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• | The termination fee payable to the Manager on termination of the Management Agreement; | ||
• | The estimated cost of internal management, until June 30, 2009, in the event of a termination of the Management Agreement; | ||
• | 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 management 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 ended 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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at December 31, 2007(1)
(Forecast Prices and Costs)
P+P | ||||||||||||||||||||||||||||||||
Value | ||||||||||||||||||||||||||||||||
Reserve | Before Tax | |||||||||||||||||||||||||||||||
P+P | Remaining | Life | at 10% | 2007 Oil | 2007 Gas | 2007 NGL | 2007 Total | |||||||||||||||||||||||||
Reserves(3) | Reserve Life | Index | Discount | Production | Production | Production | Production | |||||||||||||||||||||||||
Field | (Mboe) | (years) | (years) | ($MM) | (bblpd) | (MMcfd) | (bblpd) | (boepd)(3) | ||||||||||||||||||||||||
Light Oil | ||||||||||||||||||||||||||||||||
Judy Creek | 40,447 | 50 | 13.3 | 797.9 | 7,359 | 4.1 | 1,529 | 9,564 | ||||||||||||||||||||||||
Weyburn | 21,966 | 44 | 21.1 | 345.0 | 2,779 | — | — | 2,779 | ||||||||||||||||||||||||
Swan Hills | 17,593 | 50 | 20.1 | 255.1 | 1,968 | 1.5 | 280 | 2,505 | ||||||||||||||||||||||||
Carson Creek | 15,194 | 34 | 11.9 | 311.6 | 2,031 | 3.8 | 505 | 3,169 | ||||||||||||||||||||||||
Fenn Big Valley | 5,998 | 28 | 8.8 | 104.5 | 632 | 6.1 | 54 | 1,703 | ||||||||||||||||||||||||
Deer Mountain | 5,264 | 45 | 19.7 | 101.4 | 543 | 0.1 | 60 | 618 | ||||||||||||||||||||||||
Other(2) | 35,143 | 9.8 | 883.8 | 8,908 | 9.8 | 708 | 11,256 | |||||||||||||||||||||||||
Sub-Total | 141,605 | 13.1 | 2,799.3 | 24,220 | 25.4 | 3,136 | 31,594 | |||||||||||||||||||||||||
Heavy Oil | ||||||||||||||||||||||||||||||||
Jenner | 7,728 | 23 | 7.2 | 155.1 | 2,890 | 1.5 | 4 | 3,144 | ||||||||||||||||||||||||
Bodo | 7,658 | 41 | 12.6 | 107.9 | 1,439 | 2.5 | — | 1,862 | ||||||||||||||||||||||||
Tangleflags | 5,321 | 25 | 7.3 | 56.2 | 1,910 | 0.2 | — | 1,951 | ||||||||||||||||||||||||
Other(2) | 5,060 | 8.6 | 61.9 | 970 | 5.6 | — | 1,902 | |||||||||||||||||||||||||
Sub-Total | 25,767 | 8.6 | 381.1 | 7,209 | 9.9 | 4 | 8,859 | |||||||||||||||||||||||||
Conventional Gas | ||||||||||||||||||||||||||||||||
Olds | 26,615 | 48 | 16.4 | 293.1 | 12 | 25.0 | 769 | 4,952 | ||||||||||||||||||||||||
Harmattan | 10,857 | 36 | 7.9 | 178.8 | 346 | 10.3 | 932 | 2,993 | ||||||||||||||||||||||||
Dunvegan | 6,204 | 40 | 10.4 | 85.0 | 35 | 8.1 | 444 | 1,835 | ||||||||||||||||||||||||
Quirk Creek | 5,134 | 38 | 10.5 | 77.9 | — | 3.6 | 214 | 820 | ||||||||||||||||||||||||
Kaybob | 4,078 | 38 | 13.7 | 45.6 | — | 4.2 | 37 | 736 | ||||||||||||||||||||||||
McLeod River | 3,688 | 41 | 7.1 | 61.1 | 7 | 6.4 | 250 | 1,316 | ||||||||||||||||||||||||
Blackstone | 3,588 | 24 | 10.3 | 49.4 | — | 6.1 | — | 1,025 | ||||||||||||||||||||||||
Carson Creek | 2,958 | 39 | 5.2 | 50.6 | — | 6.2 | 397 | 1,430 | ||||||||||||||||||||||||
Other(2) | 18,788 | 7.3 | 309.1 | 523 | 43.7 | 1,332 | 9,137 | |||||||||||||||||||||||||
Sub-Total | 81,910 | 9.7 | 1,150.6 | 923 | 113.7 | 4,375 | 24,242 | |||||||||||||||||||||||||
Shallow Gas | ||||||||||||||||||||||||||||||||
Three Hills/Twining | 13,704 | 50 | 10.2 | 218.2 | 537 | 17.7 | 447 | 3,939 | ||||||||||||||||||||||||
Coal Bed Methane | 9,312 | 41 | 11.3 | 123.9 | 1 | 6.2 | 6 | 1,032 | ||||||||||||||||||||||||
Monogram | 8,044 | 32 | 8.9 | 127.0 | — | 12.1 | — | 2,015 | ||||||||||||||||||||||||
Jenner | 7,435 | 33 | 9.4 | 90.7 | 4 | 11.5 | 2 | 1,922 | ||||||||||||||||||||||||
Lethbridge | 3,685 | 50 | 7.6 | 51.2 | — | 7.2 | — | 1,193 | ||||||||||||||||||||||||
Other(2) | 16,728 | 10.0 | 247.5 | 600 | 30.2 | 18 | 5,713 |
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P+P | ||||||||||||||||||||||||||||||||
Value | ||||||||||||||||||||||||||||||||
Reserve | Before Tax | |||||||||||||||||||||||||||||||
P+P | Remaining | Life | at 10% | 2007 Oil | 2007 Gas | 2007 NGL | 2007 Total | |||||||||||||||||||||||||
Reserves(3) | Reserve Life | Index | Discount | Production | Production | Production | Production | |||||||||||||||||||||||||
Field | (Mboe) | (years) | (years) | ($MM) | (bblpd) | (MMcfd) | (bblpd) | (boepd)(3) | ||||||||||||||||||||||||
Sub-Total | 58,908 | 9.9 | 858.4 | 1,142 | 84.8 | 533 | 15,813 | |||||||||||||||||||||||||
Offshore Gas | ||||||||||||||||||||||||||||||||
Sable Island | 11,731 | 9 | 4.3 | 266.6 | — | 33.2 | 1,362 | 6,895 | ||||||||||||||||||||||||
Sub-Total | 11,731 | 4.3 | 266.6 | — | 33.2 | 1,362 | 6,895 | |||||||||||||||||||||||||
Total | 319,921 | 10.4 | 5,455.9 | 33,495 | 267.0 | 9,409 | 87,401 | |||||||||||||||||||||||||
(1) | 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. |
(2) | “Other” includes Pengrowth’s Working Interests and Royalty Interests in approximately 100 other properties. |
(3) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil. |
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• | SIFT tax starting January 2011 at 26.5 percent (and 25 percent in 2012 and thereafter) and corporate taxes as currently expected; | ||
• | Annual general and administration expenses at the current level; | ||
• | Interest expense at the current level; | ||
• | Inclusion of tax pools and deductions at the trust level as well as at the operating entity level; | ||
• | Royalties paid to the Trust in the amount of the operating income; | ||
• | Distributions to Unitholders; and | ||
• | Any such other additional deductions and adjustments as is and would be consistent with the manner in which Pengrowth files and would file future tax returns.See“Canadian Income Tax Considerations”. |
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as of December 31, 2007
(Forecast Prices and Costs)
Light and Medium Oil | Heavy Oil | Natural Gas Liquids | ||||||||||||||||||||||||||||||||||
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) | (Mbbls) | (Mbbls) | (Mbbls) | |||||||||||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||||||||||||||
Proved Developed Producing | 73,509 | 73,350 | 63,961 | 14,682 | 14,674 | 13,196 | 19,920 | 19,813 | 14,312 | |||||||||||||||||||||||||||
Proved Developed Non-Producing | 482 | 482 | 406 | 30 | 30 | 29 | 504 | 504 | 325 | |||||||||||||||||||||||||||
Proved Undeveloped | 18,986 | 18,985 | 15,690 | 2,194 | 2,194 | 1,899 | 1,361 | 1,361 | 1,053 | |||||||||||||||||||||||||||
Total Proved Reserves | 92,977 | 92,817 | 80,057 | 16,906 | 16,898 | 15,124 | 21,786 | 21,677 | 15,691 | |||||||||||||||||||||||||||
Probable Reserves | 31,211 | 31,180 | 26,533 | 4,885 | 4,883 | 4,273 | 7,208 | 7,185 | 5,195 | |||||||||||||||||||||||||||
Total Proved Plus Probable Reserves | 124,188 | 123,997 | 106,590 | 21,792 | 21,781 | 19,397 | 28,994 | 28,862 | 20,885 | |||||||||||||||||||||||||||
Natural Gas | Coal Bed Methane | Total Oil Equivalent Basis(1) | ||||||||||||||||||||||||||||||||||
Company | Gross | Net | Company | Gross | Net | Company | Gross | Net | ||||||||||||||||||||||||||||
Interest | Interest | Interest | Interest | Interest | Interest | Interest | Interest | Interest | ||||||||||||||||||||||||||||
Reserves Category | (bcf) | (bcf) | (bcf) | (bcf) | (bcf) | (bcf) | (Mboe) | (Mboe) | (Mboe) | |||||||||||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||||||||||||||
Proved Developed Producing | 547,462 | 543,054 | 437,824 | 21,257 | 20,460 | 19,101 | 202,898 | 201,755 | 167,624 | |||||||||||||||||||||||||||
Proved Developed Non-Producing | 21,168 | 21,084 | 16,044 | 2,712 | 2,632 | 2,405 | 4,997 | 4,968 | 3,835 | |||||||||||||||||||||||||||
Proved Undeveloped | 50,351 | 50,224 | 41,057 | 14,049 | 13,911 | 12,341 | 33,275 | 33,230 | 27,542 | |||||||||||||||||||||||||||
Total Proved Reserves | 618,981 | 614,363 | 494,925 | 38,018 | 37,002 | 33,847 | 241,169 | 239,953 | 199,000 | |||||||||||||||||||||||||||
Probable Reserves | 195,282 | 193,874 | 155,116 | 17,402 | 17,115 | 15,579 | 78,752 | 78,414 | 64,450 | |||||||||||||||||||||||||||
Total Proved Plus Probable Reserves | 814,263 | 808,237 | 650,041 | 55,420 | 54,117 | 49,426 | 319,921 | 318,367 | 263,450 | |||||||||||||||||||||||||||
Note: | ||
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil. |
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of Future Net Revenue
as of December 31, 2007
Before and After Income Taxes
(Forecast Prices and Costs)
Unit Value Before Income Tax | ||||||||||||||||||||||||||||
Before Income Taxes Discounted At (%/Year) | Discounted At 10%/Year(1) | |||||||||||||||||||||||||||
0% | 5% | 10% | 15% | 20% | ||||||||||||||||||||||||
Reserves Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | $/boe | $/Mcfe | |||||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||||||
Proved Developed Producing | 6,212 | 4,744 | 3,885 | 3,321 | 2,921 | 23.18 | 3.86 | |||||||||||||||||||||
Proved Developed Non-Producing | 134 | 100 | 79 | 65 | 55 | 20.57 | 3.43 | |||||||||||||||||||||
Proved Undeveloped | 1,126 | 688 | 459 | 322 | 234 | 16.66 | 2.78 | |||||||||||||||||||||
Total Proved Reserves | 7,473 | 5,532 | 4,423 | 3,708 | 3,210 | 22.22 | 3.70 | |||||||||||||||||||||
Probable Reserves | 2,960 | 1,602 | 1,033 | 740 | 565 | 16.03 | 2.67 | |||||||||||||||||||||
Total Proved Plus Probable Reserves | 10,433 | 7,134 | 5,456 | 4,448 | 3,775 | 20.71 | 3.45 | |||||||||||||||||||||
After Income Taxes Discounted At (%/Year) | ||||||||||||||||||||
0% | 5% | 10% | 15% | 20% | ||||||||||||||||
Reserves Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | |||||||||||||||
Proved Reserves | ||||||||||||||||||||
Proved Developed Producing | 5,478 | 4,344 | 3,638 | 3,149 | 2,793 | |||||||||||||||
Proved Developed Non-Producing | 99 | 77 | 63 | 53 | 46 | |||||||||||||||
Proved Undeveloped | 707 | 439 | 293 | 206 | 149 | |||||||||||||||
Total Proved Reserves | 6,284 | 4,860 | 3,994 | 3,408 | 2,988 | |||||||||||||||
Probable Reserves | 1,813 | 1,001 | 667 | 493 | 387 | |||||||||||||||
Total Proved Plus Probable Reserves | 8,097 | 5,861 | 4,661 | 3,901 | 3,375 | |||||||||||||||
Note: | ||
(1) | Unit values are based on Pengrowth’s Net reserves |
- 38 -
(undiscounted)
as of December 31, 2007
(Forecast Prices and Costs)
Future Net | ||||||||||||||||||||||||||||||||
Revenue | ||||||||||||||||||||||||||||||||
Capital | Before | Future net | ||||||||||||||||||||||||||||||
Operating | Development | Abandonment | Income | Income | Revenue | |||||||||||||||||||||||||||
Revenue | Royalties(1) | Costs | Costs | Costs(2) | Taxes | Tax | After Income | |||||||||||||||||||||||||
Reserves category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | Taxes($MM) | ||||||||||||||||||||||||
Proved Reserves | 15,750 | 2,600 | 4,898 | 566 | 214 | 7,473 | 1,189 | 6,284 | ||||||||||||||||||||||||
Total Proved Plus Probable Reserves | 21,467 | 3,584 | 6,391 | 819 | 240 | 10,433 | 2,336 | 8,097 |
Notes: | ||
(1) | Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Does not include the impact of the proposed royalty regime announced by the Government of Alberta on October 25, 2007, to become effective on January 1, 2009. Based on the interpretations by GLJ of the proposed royalty changes and based on the January 2008 commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as compared to the current royalty structure. | |
(2) | Includes downhole abandonment cost but does not include surface reclamation costs. See "Pengrowth – Operational Information – Additional Information Concerning Abandonment & Reclamation Costs”. |
By Production Group
as of December 31, 2007
(Forecast Prices and Costs)
Future Net | ||||||||||||||
Revenue Before | ||||||||||||||
Income Taxes | ||||||||||||||
(discounted at 10%/yr) | Unit Value(3) | |||||||||||||
Reserves Category | Production Group | ($MM) | ($/Boe) | ($/Mcf) | ||||||||||
Total Proved Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 2,365 | 25.57 | 4.26 | ||||||||||
Heavy Oil (including solution gas and other by-products) (1) | 305 | 18.07 | 3.01 | |||||||||||
Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 1,645 | 19.85 | 3.31 | |||||||||||
Non-conventional Oil & Gas Activities | 108 | 15.94 | 2.66 | |||||||||||
Total | 4,423 | 22.22 | 3.70 | |||||||||||
Total Proved Plus Probable Reserves | Light and Medium Crude Oil (including solution gas and other by-products) (1) | 2,881 | 23.53 | 3.92 | ||||||||||
Heavy Oil (including solution gas and other by-products)(1) | 369 | 17.03 | 2.84 | |||||||||||
Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 2,065 | 18.89 | 3.15 | |||||||||||
Non-conventional Oil & Gas Activities | 141 | 14.52 | 2.42 | |||||||||||
Total | 5,456 | 20.74 | 3.46 |
Notes: | ||
(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. | |
(3) | Unit values are based on Pengrowth’s Net reserves. |
- 39 -
as of December 31, 2007
(Constant Prices and Costs)
Height and Medium Oil | Heavy Oil | Natural Gas Liquids | ||||||||||||||||||||||||||||||||||||||
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) | (Mbbls) | (Mbbls) | (Mbbls) | |||||||||||||||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||||||||||||||||||
Proved Developed Producing | 73,715 | 73,550 | 64,184 | 14,591 | 14,583 | 13,185 | 19,922 | 19,814 | 14,274 | |||||||||||||||||||||||||||||||
Proved Developed Non- Producing | 1,040 | 1,040 | 914 | 95 | 95 | 89 | 559 | 558 | 381 | |||||||||||||||||||||||||||||||
Proved Undeveloped | 19,014 | 19,013 | 15,555 | 2,194 | 2,194 | 1,899 | 1,363 | 1,363 | 1,053 | |||||||||||||||||||||||||||||||
Total Proved Reserves | 93,769 | 93,603 | 80,653 | 16,880 | 16,872 | 15,173 | 21,845 | 21,736 | 15,708 | |||||||||||||||||||||||||||||||
Probable Reserves | 31,338 | 31,311 | 26,655 | 4,863 | 4,861 | 4,260 | 7,203 | 7,180 | 5,186 | |||||||||||||||||||||||||||||||
Total Proved Plus Probable Reserves | 125,107 | 124,914 | 107,308 | 21,744 | 21,733 | 19,433 | 29,048 | 28,916 | 20,893 | |||||||||||||||||||||||||||||||
Natural Gas | Coal Bed Methane | Total Oil Equivalent Basis(1) | ||||||||||||||||||||||||||||||||||||||
Company | Gross | Net | Company | Gross | Net | Company | Gross | Net | ||||||||||||||||||||||||||||||||
Interest | Interest | Interest | Interest | Interest | Interest | Interest | Interest | Interest | ||||||||||||||||||||||||||||||||
RESERVES CATEGORY | (bcf) | (bcf) | (bcf) | (bcf) | (bcf) | (bcf) | (Mboe) | (Mboe) | (Mboe) | |||||||||||||||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||||||||||||||||||
Proved Developed Producing | 546,528 | 542,127 | 437,085 | 21,173 | 20,376 | 19,026 | 202,845 | 201,698 | 167,661 | |||||||||||||||||||||||||||||||
Proved Developed Non- Producing | 21,555 | 21,462 | 16,328 | 2,797 | 2,716 | 2,481 | 5,752 | 5,722 | 4,519 | |||||||||||||||||||||||||||||||
Proved Undeveloped | 50,778 | 50,646 | 41,437 | 14,049 | 13,911 | 12,341 | 33,376 | 33,330 | 27,470 | |||||||||||||||||||||||||||||||
Total Proved Reserves | 618,861 | 614,234 | 494,850 | 38,019 | 37,003 | 33,848 | 241,974 | 240,751 | 199,650 | |||||||||||||||||||||||||||||||
Probable Reserves | 195,196 | 193,799 | 155,060 | 17,403 | 17,116 | 15,579 | 78,838 | 78,505 | 64,541 | |||||||||||||||||||||||||||||||
Total Proved Plus Probable Reserves | 814,057 | 808,033 | 649,910 | 55,422 | 54,119 | 49,427 | 320,812 | 319,256 | 264,191 | |||||||||||||||||||||||||||||||
Note: | ||
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil. |
- 40 -
of Future Net Revenue
as of December 31, 2007
Before and After Income Tax
(Constant Prices and Costs)
Unit Value Before Income | ||||||||||||||||||||||||||||
Tax Discounted at | ||||||||||||||||||||||||||||
Before Income Taxes Discounted at (%/Year) | 10%/Year(1) | |||||||||||||||||||||||||||
0% | 5% | 10% | 15% | 20% | ||||||||||||||||||||||||
Reserves Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | $/boe | $/Mcfe | |||||||||||||||||||||
Proved Reserves | ||||||||||||||||||||||||||||
Proved Developed Producing | 6,463 | 4,900 | 3,984 | 3,383 | 2,959 | 23.76 | 3.96 | |||||||||||||||||||||
Proved Developed Non-Producing | 170 | 124 | 96 | 79 | 66 | 21.34 | 3.56 | |||||||||||||||||||||
Proved Undeveloped | 1,205 | 747 | 505 | 359 | 263 | 18.37 | 3.06 | |||||||||||||||||||||
Total Proved Reserves | 7,839 | 5,770 | 4,585 | 3,821 | 3,288 | 22.96 | 3.83 | |||||||||||||||||||||
Probable Reserves | 2,810 | 1,574 | 1,034 | 747 | 572 | 16.02 | 2.67 | |||||||||||||||||||||
Total Proved Plus Probable Reserves | 10,649 | 7,345 | 5,619 | 4,567 | 3,861 | 21.27 | 3.54 | |||||||||||||||||||||
After Income Taxes Discounted at (%/u/c year) | ||||||||||||||||||||
0% | 5% | 10% | 15% | 20% | ||||||||||||||||
Reserves Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | |||||||||||||||
Proved Reserves | ||||||||||||||||||||
Proved Developed Producing | 5,614 | 4,423 | 3,681 | 3,171 | 2,802 | |||||||||||||||
Proved Developed Non-Producing | 122 | 83 | 75 | 63 | 54 | |||||||||||||||
Proved Undeveloped | 668 | 413 | 279 | 197 | 141 | |||||||||||||||
Total Proved Reserves | 6,404 | 4,929 | 4,035 | 3,431 | 2,997 | |||||||||||||||
Probable Reserves | 1,823 | 1,054 | 717 | 534 | 422 | |||||||||||||||
Total Proved Plus Probable Reserves | 8,227 | 5,983 | 4,752 | 3,965 | 3,419 | |||||||||||||||
Note: | ||
(1) | Unit values are based on Pengrowth’s Net reserves. |
- 41 -
(undiscounted)
as of December 31, 2007
(Constant Prices and Costs)
Future Net | ||||||||||||||||||||||||||||||||
Capital | Future Net | Revenue | ||||||||||||||||||||||||||||||
Operating | Development | Abandonment | Revenue Before | After Income | ||||||||||||||||||||||||||||
Revenue | Royalties(1) | Costs | Costs | Costs(2) | Income Taxes | Income Tax | Taxes | |||||||||||||||||||||||||
Reserves Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ||||||||||||||||||||||||
Proved Reserves | 15,186 | 2,526 | 4,131 | 526 | 164 | 7,839 | 1,435 | 6,404 | ||||||||||||||||||||||||
Total Proved Plus Probable Reserves | 20,154 | 3,402 | 5,175 | 758 | 170 | 10,649 | 2,422 | 8,227 |
Notes: | ||
(1) | Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Does not include the impact of the proposed royalty regime announced by the Government of Alberta on October 25, 2007, to become effective on January 1, 2009. Based on the interpretations by GLJ of the proposed royalty changes and based on the January 2008 commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as compared to the current royalty structure. | |
(2) | Includes downhole abandonment cost but does not include surface reclamation costs. See "Pengrowth – Operational Information – Additional Information Concerning Abandonment & Reclamation Costs”. |
By Production Group
as of December 31, 2007
(Constant Prices and Costs)
Future Net Revenue | ||||||||||||||
Before Income Taxes | ||||||||||||||
(discounted at 10%/yr) | Unit Value(3) | |||||||||||||
Reserves Category | Production Group | ($MM) | ($/boe) | ($/Mcf) | ||||||||||
Total Proved Reserves | Light and Medium Crude Oil (including solution gas and other by-products)(1) | 2,755 | 29.58 | 4.93 | ||||||||||
Heavy Oil (including solution gas and other by-products) (1) | 241 | 14.19 | 2.37 | |||||||||||
Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 1,500 | 18.11 | 3.02 | |||||||||||
Non-conventional Oil & Gas Activities | 89 | 13.16 | 2.19 | |||||||||||
Total | 4,585 | 22.96 | 3.83 | |||||||||||
Total Proved Plus Probable Reserves | Light and Medium Crude Oil (including solution gas and other by-products) (1) | 3,340 | 27.11 | 4.52 | ||||||||||
Heavy Oil (including solution gas and other by-products)(1) | 291 | 13.42 | 2.24 | |||||||||||
Natural Gas (including by-products but excluding solution gas from oil wells)(2) | 1,873 | 17.14 | 2.86 | |||||||||||
Non-conventional Oil & Gas Activities | 114 | 11.75 | 1.96 | |||||||||||
Total | 5,619 | 21.29 | 3.55 |
Notes: | ||
(1) | NGL’s associated with the production of solution gas are included as a by-product. | |
(2) | NGL’s associated with the production of natural gas are included as a by-product. | |
(3) | Unit values are based on Pengrowth’s Net reserves. |
- 42 -
Oil | Natural Gas | Natural Gas Liquids(1) | ||||||||||||||||||||||
WTI | Edmonton | Cromer | Hardisty | |||||||||||||||||||||
Cushing | Par Price | Medium | Heavy 120 | AECO Gas | Pentanes | Inflation | Exchange | |||||||||||||||||
Oklahoma | 400API | 29.30API | API | Price | Propane | Butane | Plus | Rates(2) | Rate(3) | |||||||||||||||
Year | ($US/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/MMbtu) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | (%/Year) | ($US/Cdn) | ||||||||||||||
2007(4) | 72.24 | 77.02 | 66.30 | 44.37 | 6.65 | 46.85 | 58.35 | 77.33 | — | — | ||||||||||||||
2008 | 92.00 | 91.10 | 79.26 | 54.02 | 6.75 | 58.30 | 72.88 | 92.92 | 2.0 | 1.00 | ||||||||||||||
2009 | 88.00 | 87.10 | 75.78 | 51.61 | 7.55 | 55.74 | 69.68 | 88.84 | 2.0 | 1.00 | ||||||||||||||
2010 | 84.00 | 83.10 | 72.30 | 49.19 | 7.60 | 53.18 | 66.48 | 84.76 | 2.0 | 1.00 | ||||||||||||||
2011 | 82.00 | 81.10 | 70.56 | 47.98 | 7.60 | 51.90 | 64.88 | 82.72 | 2.0 | 1.00 | ||||||||||||||
2012 | 82.00 | 81.10 | 70.56 | 47.98 | 7.60 | 51.90 | 64.88 | 82.72 | 2.0 | 1.00 | ||||||||||||||
2013 | 82.00 | 81.10 | 70.56 | 49.04 | 7.60 | 51.90 | 64.88 | 82.72 | 2.0 | 1.00 | ||||||||||||||
2014 | 82.00 | 81.10 | 70.56 | 50.09 | 7.80 | 51.90 | 64.88 | 82.72 | 2.0 | 1.00 | ||||||||||||||
2015 | 82.00 | 81.10 | 70.56 | 51.15 | 7.97 | 51.90 | 64.88 | 82.72 | 2.0 | 1.00 | ||||||||||||||
2016 | 82.02 | 81.12 | 70.57 | 52.21 | 8.14 | 51.91 | 64.89 | 82.74 | 2.0 | 1.00 | ||||||||||||||
2017 | 83.66 | 82.76 | 72.00 | 53.29 | 8.31 | 52.97 | 66.21 | 84.42 | 2.0 | 1.00 | ||||||||||||||
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 | 2.0 | 1.00 |
Notes: | ||
(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 for 2007. |
Oil | Natural Gas | Natural Gas Liquids(1) | ||||||||||||||||||||||||||||||||||
WTI | Edmonton | Cromer | LLB Crude | |||||||||||||||||||||||||||||||||
Cushing | Par Price | Medium | Oil at | AECO Gas | Pentanes | Exchange | ||||||||||||||||||||||||||||||
Oklahoma | 40o API | 29.3o API | Hardisty | Price | Propane | Butane | Plus | Rate(2) | ||||||||||||||||||||||||||||
Year | ($US/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/MMbtu) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($US/Cdn) | |||||||||||||||||||||||||||
December 31, 2007 | 95.92 | 93.39 | 74.26 | 53.74 | 6.63 | 59.77 | 74.71 | 94.24 | 1.012 |
Notes: | ||
(1) | FOB Edmonton. | |
(2) | The exchange rate used to generate the benchmark reference prices in this table. |
- 43 -
By Principle Product Type
(Forecast Prices and Costs)
Light and Medium Oil | Heavy Oil | Natural Gas Liquids | ||||||||||||||||||||||||||||||||||
Gross | ||||||||||||||||||||||||||||||||||||
Gross | Gross | Proved | ||||||||||||||||||||||||||||||||||
Gross | Gross | Proved Plus | Gross | Gross | Proved Plus | Gross | Gross | Plus | ||||||||||||||||||||||||||||
Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||||||||||||
(Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | ||||||||||||||||||||||||||||
December 31, 2006 | 84,648 | 27,467 | 112,115 | 14,236 | 4,090 | 18,326 | 22,400 | 6,682 | 29,082 | |||||||||||||||||||||||||||
Extensions | 932 | (141 | ) | 791 | 30 | 10 | 40 | 496 | (1 | ) | 495 | |||||||||||||||||||||||||
Infill Drilling | 1,188 | 956 | 2,144 | — | — | — | 235 | 160 | 395 | |||||||||||||||||||||||||||
Improved Recovery | 482 | 421 | 903 | — | — | — | 25 | 15 | 40 | |||||||||||||||||||||||||||
Technical Revisions | 3,119 | (1,421 | ) | 1,698 | 742 | (177 | ) | 565 | 591 | 174 | 765 | |||||||||||||||||||||||||
Discoveries | — | — | — | — | — | — | 23 | 3 | 26 | |||||||||||||||||||||||||||
Acquisitions | 14,256 | 4,893 | 19,149 | 5,939 | 1,542 | 7,481 | 2,828 | 629 | 3,457 | |||||||||||||||||||||||||||
Dispositions | (2,227 | ) | (993 | ) | (3,220 | ) | (1,432 | ) | (582 | ) | (2,014 | ) | (1,509 | ) | (478 | ) | (1,987 | ) | ||||||||||||||||||
Economic Factors | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Production | (9,582 | ) | — | (9,582 | ) | (2,616 | ) | — | (2,616 | ) | (3,411 | ) | — | (3,411 | ) | |||||||||||||||||||||
December 31, 2007 | 92,817 | 31,180 | 123,997 | 16,898 | 4,883 | 21,781 | 21,677 | 7,185 | 28,862 |
Natural Gas | Coal Bed Methane | Total Oil Equivalent Basis(1) | ||||||||||||||||||||||||||||||||||
Gross | ||||||||||||||||||||||||||||||||||||
Gross | Gross | Proved | ||||||||||||||||||||||||||||||||||
Gross | Gross | Proved Plus | Gross | Gross | Proved Plus | Gross | Gross | Plus | ||||||||||||||||||||||||||||
Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||||||||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||||||||||||
December 31, 2006 | 608,105 | 191,206 | 799,311 | 14,230 | 9,427 | 23,657 | 225,007 | 71,677 | 296,684 | |||||||||||||||||||||||||||
Extensions | 16,729 | 5,195 | 21,924 | 14,055 | 4,883 | 18,938 | 6,588 | 1,548 | 8,136 | |||||||||||||||||||||||||||
Infill Drilling | 11,350 | 7,846 | 19,196 | — | — | 3,314 | 2,424 | 5,738 | ||||||||||||||||||||||||||||
Improved Recovery | 508 | 221 | 729 | — | — | — | 592 | 472 | 1,064 | |||||||||||||||||||||||||||
Technical Revisions | 14,661 | (19,175 | ) | (4,514 | ) | 1,791 | (1,543 | ) | 248 | 7,193 | (4,877 | ) | 2,316 | |||||||||||||||||||||||
Discoveries | 519 | 234 | 753 | 338 | 112 | 450 | 165 | 62 | 227 | |||||||||||||||||||||||||||
Acquisitions | 155,961 | 36,584 | 192,545 | 8,434 | 4,235 | 12,669 | 50,422 | 13,867 | 64,289 | |||||||||||||||||||||||||||
Dispositions | (99,088 | ) | (28,236 | ) | (127,324 | ) | — | — | — | (21,682 | ) | (6,760 | ) | (28,442 | ) | |||||||||||||||||||||
Economic Factors | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Production | (94,384 | ) | — | (94,384 | ) | (1,845 | ) | — | (1,845 | ) | (31,648 | ) | — | (31,648 | ) | |||||||||||||||||||||
December 31, 2007 | 614,363 | 193,874 | 808,237 | 37,002 | 17,115 | 54,117 | 239,953 | 78,413 | 318,366 |
Note: | ||
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil. |
- 44 -
on Total Oil Equivalent Basis
(Forecast Prices and Costs)
Proved Plus | ||||||||||||
Proved Producing | Proved | Probable | ||||||||||
Reserves | Reserves | Reserves | ||||||||||
(Mboe)(1) | (Mboe)(1) | (Mboe)(1) | ||||||||||
December 31, 2006 | 188,961 | 225,875 | 297,774 | |||||||||
Extensions | 4,898 | 6,588 | 8,136 | |||||||||
Infill Drilling | 3,956 | 3,314 | 5,738 | |||||||||
Improved Recovery | 755 | 592 | 1,180 | |||||||||
Technical Revisions | 11,094 | 7,170 | 2,094 | |||||||||
Discoveries | 109 | 165 | 227 | |||||||||
Acquisitions | 44,721 | 51,046 | 65,115 | |||||||||
Dispositions | (19,696 | ) | (21,682 | ) | (28,442 | ) | ||||||
Production | (31,901 | ) | (31,901 | ) | (31,901 | ) | ||||||
December 31, 2007 | 202,897 | 241,169 | 319,921 | |||||||||
Note: | ||
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil. |
• | Reserve additions from drilling activity, improved recovery and technical revisions replaced 2007 production by 56 percent and 54 percent for Total Proved and Proved Plus Probable Reserves, respectively. Based on all changes, including acquisitions and dispositions, reserve replacement was 148 percent and 169 percent for Total Proved and Proved Plus Probable Reserves, respectively. | ||
• | The net increase of 36.7 MMboe from acquisitions and dispositions accounted for approximately 68 percent of the Total Proved Plus Probable Reserves added in 2007. Acquisition adds were almost entirely from the ConocoPhillips properties acquired in January 2007. Acquisitions were offset by the planned sale of non-core assets closing at various times during 2007. | ||
• | New reserves were added from development activity. Most significant were drilling extensions for Horseshoe Canyon CBM and infill drilling and drilling extensions at Twining, Harmattan and Monogram. Reserve increases in the Proved Producing category also resulted from reclassification of Proved and Probable Undeveloped Reserves primarily for additional drilling and tie-in of Horseshoe Canyon CBM, infill drilling at Monogram and infill drilling and improved recovery in the Weyburn and Swan Hills miscible flood projects. | ||
• | Various performance related revisions were made to previous estimates resulting in a net positive change. The largest revisions to Proved Reserves occurred at Sable Island (+1,308 Mboe), Fenn Big Valley (+965 Mboe), Jenner (+887 Mboe) and Winnifred (-520 Mboe). |
- 45 -
Company Gross Reserves
Reserves First Attributed By Year
Units | Prior | 2005 | 2006 | 2007 | Total | |||||||||||||||||||
Proved Undeveloped | ||||||||||||||||||||||||
Light & Medium Oil | Mbbl | 8,498 | 7,221 | 1,334 | 1,932 | 18,985 | ||||||||||||||||||
Heavy Oil | Mbbl | 1,852 | — | — | 342 | 2,194 | ||||||||||||||||||
Natural Gas | MMcf | 7,236 | 3,508 | 18,575 | 20,905 | 50,224 | ||||||||||||||||||
Natural Gas Liquids | Mbbl | 120 | — | 843 | 398 | 1,361 | ||||||||||||||||||
Coal Bed Methane | MMcf | — | — | 2,555 | 11,356 | 13,911 | ||||||||||||||||||
Total | Mboe(1) | 11,754 | 7,730 | 5,698 | 8,048 | 33,230 | ||||||||||||||||||
�� | ||||||||||||||||||||||||
Probable Undeveloped | ||||||||||||||||||||||||
Light & Medium Oil | Mbbl | 5,995 | 3,123 | 1,315 | 3,065 | 13,498 | ||||||||||||||||||
Heavy Oil | Mbbl | 1,343 | — | 200 | 726 | 2,269 | ||||||||||||||||||
Natural Gas | MMcf | 2,744 | 3,598 | 33,258 | 25,386 | 64,986 | ||||||||||||||||||
Natural Gas Liquids | Mbbl | 112 | 648 | 1,286 | 670 | 2,716 | ||||||||||||||||||
Coal Bed Methane | MMcf | — | — | 1,985 | 8,170 | 10,155 | ||||||||||||||||||
Total | Mboe(1) | 7,907 | 4,371 | 8,674 | 10,054 | 31,006 |
Note: | ||
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil. |
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Undiscounted | Discounted | |||||||||||||||||||||||||||||||
2008 | 2009 | 2010 | 2011 | 2012 | Remainder | Total | at 10% Total | |||||||||||||||||||||||||
Reserve Category | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ($MM) | ||||||||||||||||||||||||
Proved Reserves (Constant Prices and Costs) | 183 | 103 | 63 | 33 | 18 | 126 | 526 | 393 | ||||||||||||||||||||||||
Proved Reserves (Forecast Prices and Costs) | 183 | 105 | 65 | 35 | 19 | 158 | 566 | 408 | ||||||||||||||||||||||||
Proved & Probable Reserves (Forecast Prices and Costs) | 230 | 180 | 100 | 47 | 29 | 234 | 819 | 584 |
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Company Interest Reserves
Proved plus | ||||||||
Proved | Probable | |||||||
FD&A Costs Excluding Future Development Capital | ||||||||
Exploration and Development Capital Expenditures ($thousands) | $ | 283,100 | $ | 283,100 | ||||
Exploration and Development Reserve Additions including Revisions (Mboe) | 17,830 | 17,376 | ||||||
Finding and Development Cost ($/boe) | $ | 15.88 | $ | 16.29 | ||||
Net Acquisition Capital ($thousands) | $ | 577,100 | $ | 577,100 | ||||
Net Acquisition Reserve Additions (Mboe) | 29,364 | 36,673 | ||||||
Net Acquisition Cost ($/boe) | $ | 19.65 | $ | 15.74 | ||||
Total Capital Expenditures including Net Acquisitions ($thousands) | $ | 860,200 | $ | 860,200 | ||||
Reserve Additions including Net Acquisitions (Mboe) | 47,194 | 54,049 | ||||||
Finding Development and Acquisition Cost ($/boe) | $ | 18.23 | $ | 15.92 | ||||
FD&A Costs Including Future Development Capital | ||||||||
Exploration and Development Capital Expenditures ($thousands) | $ | 283,100 | $ | 283,100 | ||||
Exploration and Development Change in FDC ($thousands) | $ | 8,000 | $ | 20,000 | ||||
Exploration and Development Capital including Change in FDC ($thousands) | $ | 291,100 | $ | 303,100 | ||||
Exploration and Development Reserve Additions including Revisions (Mboe) | 17,830 | 17,376 | ||||||
Finding and Development Cost ($/boe) | $ | 16.33 | $ | 17.44 | ||||
Net Acquisition Capital ($thousands) | $ | 577,100 | $ | 577,100 | ||||
Net Acquisition FDC ($thousands) | $ | 115,000 | $ | 145,000 | ||||
Net Acquisition Capital including FDC ($thousands) | $ | 692,100 | $ | 722,100 | ||||
Net Acquisition Reserve Additions (Mboe) | 29,364 | 36,673 | ||||||
Net Acquisition Cost ($/boe) | $ | 23.57 | $ | 19.69 | ||||
Total Capital Expenditures including Net Acquisitions ($thousands) | $ | 860,200 | $ | 860,200 | ||||
Total Change in FDC ($thousands) | $ | 123,000 | $ | 165,000 | ||||
Total Capital including Change in FDC ($thousands) | $ | 983,300 | $ | 1,025,300 | ||||
Reserve Additions including Net Acquisitions (Mboe) | 47,194 | 54,049 | ||||||
Finding Development and Acquisition Cost including FDC ($/boe) | $ | 20.83 | $ | 18.97 | ||||
Note: | ||
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil. |
Producing | Non-Producing | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Crude Oil Wells | ||||||||||||||||
Alberta | 2,346 | 1,473 | 473 | 277 | ||||||||||||
British Columbia | 151 | 105 | 47 | 43 | ||||||||||||
Saskatchewan | 1,134 | 279 | 187 | 81 | ||||||||||||
Nova Scotia | — | — | — | — | ||||||||||||
Natural Gas Wells | ||||||||||||||||
Alberta | 5,515 | 2,827 | 571 | 322 | ||||||||||||
British Columbia | 124 | 77 | 25 | 27 | ||||||||||||
Saskatchewan | �� | 51 | 48 | 87 | 47 | |||||||||||
Nova Scotia | 19 | 1 | — | — | ||||||||||||
Other(1) | ||||||||||||||||
Alberta | 250 | 217 | 165 | 115 | ||||||||||||
British Columbia | — | — | 50 | 46 | ||||||||||||
Saskatchewan | 14 | 10 | 22 | 19 | ||||||||||||
Total | 9,604 | 5,038 | 1,627 | 976 | ||||||||||||
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Note: | ||
(1) | Pengrowth cannot classify these wells as either oil or gas. |
as at December 31, 2007
Net Area May Expire | ||||||||||||
Location | Gross Acres | Net Acres | During 2008 | |||||||||
Alberta | 1,095,994 | 754,253 | 129,887 | |||||||||
British Columbia | 255,172 | 116,763 | 13,847 | |||||||||
Ontario | 4,766 | — | — | |||||||||
Saskatchewan | 90,989 | 76,335 | 30,039 | |||||||||
Montana | 3,520 | 3,520 | 3,520 | |||||||||
Nova Scotia | 200,650 | 15,957 | — | |||||||||
Total | 1,651,091 | 966,828 | 177,293 | |||||||||
2008 | 2009 | 2010 | Remainder | Total | ||||||||||||||||
($M) | ($M) | ($M) | ($M) | ($M) | ||||||||||||||||
Total Abandonment, Reclamation, Remediation & Dismantling | 17,287 | 18,046 | 21,363 | 1,958,381 | 2,015,077 | |||||||||||||||
Discounted at 10 percent | 16,483 | 15,642 | 16,834 | 220,908 | 269,867 |
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Amount | ||||
Nature of Cost | ($MM) | |||
Acquisition Costs(1) | ||||
Proved | 823,566 | |||
Unproved | 212,317 | |||
Exploration Costs | 21,192 | |||
Development Costs | 261,866 | |||
Total | 1,318,941 | |||
Note: | ||
(1) | Based on the values assigned to property, plant and equipment in the purchase price allocations for the CP Acquisition and for several minor property acquisitions. |
Development | Exploration | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Wells | ||||||||||||||||||||||||
Gas | 383 | 130.7 | 6 | 2.2 | 389 | 132.9 | ||||||||||||||||||
Oil | 84 | 19.9 | 6 | 5.3 | 90 | 25.2 | ||||||||||||||||||
Service | 15 | 8.4 | — | — | 15 | 8.4 | ||||||||||||||||||
Dry | 12 | 5.6 | 5 | 2.6 | 17 | 8.2 | ||||||||||||||||||
Total | 494 | 164.6 | 17 | 10.1 | 511 | 174.7 | ||||||||||||||||||
Estimated Production | ||||||||||||||||
Constant Prices and Costs | Forecast Prices and Costs | |||||||||||||||
Total Proved Plus | Total Proved Plus | |||||||||||||||
Total Proved | Probable | Total Proved | Probable | |||||||||||||
Light and Medium Crude Oil (bblpd) | 24,933 | 26,169 | 24,933 | 26,169 | ||||||||||||
Heavy Oil (bblpd) | 6,485 | 6,711 | 6,485 | 6,711 | ||||||||||||
Natural Gas (Mcfpd) | 245,006 | 255,631 | 245,007 | 255,631 | ||||||||||||
Natural Gas Liquids (bblpd) | 8,250 | 8,526 | 8,250 | 8,526 |
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Quarter Ended | ||||||||||||||||
March 31, | June 30, | September 30, | December 31, | |||||||||||||
2007 | 2007 | 2007 | 2007 | |||||||||||||
Light Crude Oil | ||||||||||||||||
Average Daily Oil Production(1) (bblpd) | 27,461 | 27,083 | 24,903 | 25,892 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/bbl) | 67.24 | 71.81 | 75.10 | 73.69 | ||||||||||||
Processing and other income ($/bbl) | 0.39 | 0.42 | 0.90 | 0.69 | ||||||||||||
Royalties ($/bbl) | (9.88 | ) | (11.90 | ) | (10.65 | ) | (13.86 | ) | ||||||||
Amortization of injectants ($/bbl) | (3.84 | ) | (3.51 | ) | (3.69 | ) | (3.14 | ) | ||||||||
Production Costs(2)($/bbl) | (13.31 | ) | (15.11 | ) | (16.93 | ) | (15.69 | ) | ||||||||
Operating Netback ($/bbl) | 40.60 | 41.71 | 44.73 | 41.69 | ||||||||||||
Heavy Oil | ||||||||||||||||
Average Daily Oil Production(1) (bblpd) | 6,773 | 7,254 | 7,205 | 7,434 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/bbl) | 41.54 | 43.52 | 47.30 | 45.47 | ||||||||||||
Processing and other income ($/bbl) | 0.18 | 0.18 | 0.50 | 0.19 | ||||||||||||
Royalties ($/bbl) | (5.23 | ) | (5.33 | ) | (6.90 | ) | (5.91 | ) | ||||||||
Production Costs(2)($/bbl) | (13.15 | ) | (15.37 | ) | (9.43 | ) | (12.92 | ) | ||||||||
Operating Netback ($/bbl) | 23.34 | 23.00 | 31.47 | 26.83 | ||||||||||||
NGLs | ||||||||||||||||
Average Daily NGL Production(1) (bblpd) | 9,918 | 8,519 | 9,883 | 9,319 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/bbl) | 49.67 | 56.42 | 61.69 | 67.64 | ||||||||||||
Royalties ($/bbl) | (14.05 | ) | (17.53 | ) | (18.82 | ) | (23.61 | ) | ||||||||
Production Costs(2)($/bbl) | (12.02 | ) | (13.57 | ) | (10.96 | ) | (14.29 | ) | ||||||||
Operating Netback ($/bbl) | 23.60 | 25.32 | 31.91 | 29.74 | ||||||||||||
Natural Gas | ||||||||||||||||
Average Daily Gas Production(1) (Mcfpd) | 275,495 | 280,667 | 261,976 | 250,117 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/Mcf) | 7.91 | 7.61 | 6.67 | 6.90 | ||||||||||||
Processing and other income ($/Mcf) | 0.15 | 0.16 | 0.19 | 0.18 | ||||||||||||
Royalties ($/Mcf) | (1.67 | ) | (1.47 | ) | (0.92 | ) | (1.22 | ) | ||||||||
Production Costs(2)($/Mcf) | (2.10 | ) | (2.24 | ) | (1.58 | ) | (2.11 | ) | ||||||||
Operating Netback ($/Mcf) | 4.29 | 4.06 | 4.36 | 3.75 | ||||||||||||
Barrels of Oil Equivalent Basis(3) | ||||||||||||||||
Average Daily Production(1) (boepd) | 90,068 | 89,633 | 85,654 | 84,331 | ||||||||||||
Sales Price (net of hedging gains/losses) ($/boe) | 53.30 | 54.39 | 53.34 | 54.58 | ||||||||||||
Processing and other income ($/boe) | 0.58 | 0.66 | 0.90 | 0.76 | ||||||||||||
Royalties ($/boe) | (10.06 | ) | (10.30 | ) | (8.67 | ) | (11.01 | ) | ||||||||
Amortization of injectants ($/boe) | (1.17 | ) | (1.06 | ) | (1.07 | ) | (0.97 | ) | ||||||||
Production Costs(2) ($/boe) | (12.78 | ) | (14.13 | ) | (11.84 | ) | (13.80 | ) | ||||||||
Operating Netback ($/boe) | 29.87 | 29.56 | 32.66 | 29.56 |
Notes: | ||
(1) | Before the deduction of royalties. | |
(2) | Includes transportation costs. Net of processing and other income. | |
(3) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one boe. |
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($ thousands, | ||||
unless otherwise indicated) | ||||
Value of Total Proved Plus Probable Reserves | 5,455,881 | |||
Undeveloped lands(1) | 239,893 | |||
Working capital deficit(2) | (34,423 | ) | ||
Reclamation funds | 18,094 | |||
Long-term debt | (1,203,236 | ) | ||
Fair value of risk management contracts(3) | (79,401 | ) | ||
Other liabilities(4) | (87,192 | ) | ||
Asset retirement obligations(5) | (206,868 | ) | ||
Net asset value | 4,102,748 | |||
Units outstanding (000’s) | 246,846 | |||
NAV per unit | $ | 16.62 |
Notes: | ||
(1) | Pengrowth’s internal estimate, calculated using the average land sale prices paid in 2007 in Alberta, Saskatchewan and British Columbia. | |
(2) | Excludes distributions payable, current portion of risk management contracts and future income taxes. | |
(3) | Represents the total fair value of risk management contracts at December 31, 2007. | |
(4) | Other liabilities include convertible debt and non-current contract liabilities. | |
(5) | The asset retirement obligation is based on Pengrowth’s estimate of future site restoration and abandonment liabilities, discounted at 10 percent, less that portion of the asset retirement obligations costs that are included in the value of Total Proved Plus Probable Reserves. |
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• | a vote may be held only if: (i) requested in writing by the holders of not less than 25 percent of the Trust Units and class A trust units, in the aggregate; or (ii) if the Trust Units and the class A trust units have become ineligible for investment by RRSPs, RRIFs, RESPs and DPSPs; | ||
• | the termination must be approved by extraordinary resolution of the Unitholders; and |
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• | a quorum representing 5 percent of the issued and outstanding Trust Units and class A trust units, in the aggregate, must be present or represented by proxy at the meeting at which the vote is taken. |
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• | operating costs and capital expenditures; | ||
• | general and administrative costs; | ||
• | management fees and debt service charges; | ||
• | taxes or other charges payable by the Corporation; and | ||
• | any amounts paid into the “reserve”. |
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2007 | 2006 | 2005 | 2004 | 2003 | 2002 | |||||||||||||||||||
First Quarter | $ | 0.75 | $ | 0.75 | $ | 0.69 | $ | 0.63 | $ | 0.75 | $ | 0.41 | ||||||||||||
Second Quarter | 0.75 | 0.75 | 0.69 | 0.64 | 0.67 | 0.54 | ||||||||||||||||||
Third Quarter | 0.75 | 0.75 | 0.69 | 0.67 | 0.63 | 0.52 | ||||||||||||||||||
Fourth Quarter | 0.675 | (1) | 0.75 | 0.75 | 0.69 | 0.63 | 0.60 | |||||||||||||||||
Total | $ | 2.93 | $ | 3.00 | $ | 2.82 | $ | 2.63 | $ | 2.68 | $ | 2.07 | ||||||||||||
Notes: | ||
(1) | On October 15, 2007, November 15, 2007 and December 15, 2007, the monthly distribution paid to Unitholders was $0.225 per Trust Unit, representing a reduction of 10 percent from the monthly distribution of $0.25 per Trust Unit for the first three quarters of 2007. | |
(2) | Based on actual distributions declared. |
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2007 | 2006 | 2005 | 2004 | 2003 | 2002 | |||||||||||||||||||
Taxable Income(1)(per Trust Unit) | $ | 2.78 | $ | 2.40 | $ | 2.22 | $ | 1.43 | $ | 1.47 | $ | 0.45 | ||||||||||||
(percent of distributions classified as taxable income) | (95 | %) | (80 | %) | (80 | %) | (55 | %) | (55 | %) | (22 | %) |
Note: | ||
(1) | For Canadian residents, amounts treated as a return of capital generally are not required to be included in a Unitholder’s income but such amounts will reduce the adjusted cost base to the Unitholder of the Trust Units. |
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• | the ratio of Consolidated Senior Debt (as defined below) to Consolidated EBITDA (as defined below) at the end of any fiscal quarter shall not exceed 3:1, except that upon the completion of a Material Acquisition (as defined below), and for a period extending to the end of the second full fiscal quarter thereafter, this limit increases to 3.5:1; | ||
• | the ratio of Consolidated Total Debt (as defined below) to Consolidated EBITDA at the end of any fiscal quarter shall not exceed 3.5:1; except that upon the completion of a Material Acquisition, and for a period extending to the end of the second full fiscal quarter thereafter, this limit increases to 4:1; and | ||
• | the ratio of Consolidated Senior Debt (as defined below) to Total Capitalization (as defined below) shall not exceed 50 percent, except that upon the completion of a Material Acquisition, and for a period extending to the end of the second full fiscal quarter thereafter, this limit increases to 55 percent. |
Consolidated Senior Debt: | All obligations, liabilities and indebtedness that would be classified as debt on the consolidated balance sheet of the Trust, including, without limitation, certain items including all indebtedness for borrowed money, but excluding certain items. | |
Consolidated Total Debt: | The aggregate of Consolidated Senior Debt and Subordinated Debt. | |
Consolidated EBITDA: | The aggregate of the last four quarters’ net income from operations plus the sum of: | |
• income taxes; | ||
• interest expense; | ||
• all provisions for federal, provincial or other income and capital taxes; | ||
• depreciation, depletion and amortization expense; and | ||
• other non-cash amounts. | ||
Material Acquisition: | An acquisition or series of acquisitions which increases the consolidated tangible assets of Pengrowth by more than 5 percent. | |
Subordinated Debt: | Debt which, by its terms, is subordinated to the obligations to the lenders under the Credit Facility. |
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Total Capitalization: | The aggregate of Consolidated Total Debt and the Unitholders’ equity (calculated in accordance with GAAP as shown on the Trust’s consolidated balance sheet) |
• | the ratio of Consolidated EBITDA (as defined below) to interest expense for the four immediately preceding fiscal quarters shall be not less than 4:1; | ||
• | with respect to the 2003 U.S. Senior Notes and the U.K. Senior Notes only, the Consolidated Total Debt (as defined below) is limited to 60 percent of the Consolidated Total Established Reserves (as defined below) determined and calculated not later than the last day of the first fiscal quarter of the next succeeding fiscal year of the Trust; | ||
• | with respect to the 2007 U.S. Senior Notes only, the Consolidated Total Debt (as defined below) to Total Capitalization (as defined below) shall not exceed 55 percent at the end of each fiscal quarter; and | ||
• | the ratio of Consolidated Total Debt to Consolidated EBITDA for each period of four consecutive fiscal quarters shall not exceed 3.5:1. |
Consolidated EBITDA: | The sum of the last four quarters of: (i) net income determined in accordance with GAAP; (ii) all provisions for federal, provincial or other income and capital taxes; (iii) all provisions for depletion, depreciation, and amortization; (iv) interest expense; and (v) non-cash items. | |
Consolidated Total Debt: | Has substantially the same meaning as “Consolidated Senior Debt” in the definitions relating to the Credit Facility. | |
Consolidated Total Established Reserves: | The sum of: (i) 100 percent of the present value of Pengrowth’s proved reserves; and (ii) 50 percent of the present value of Pengrowth’s probable reserves. | |
Total Capitalization: | Consolidated Total Debt plus Unitholder equity in the Trust. |
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• | the Trust is required to punctually pay or cause to be paid all principal, premium and interest amounts as prescribed by the Debenture Indenture, as amended; | ||
• | the Trust is required to pay the trustee under the Debenture Indenture reasonable remuneration for its services as trustee and repay on demand all monies which have been paid by the trustee in execution of its obligations thereunder; | ||
• | the Trust is required to provide the trustee under the Debenture Indenture with notification immediately upon obtaining knowledge of any Event of Default; | ||
• | the Trust is required to carry on its business in a proper, efficient and business-like manner and in accordance with good business practices; | ||
• | the Trust is required to deliver to the trustee under the Debenture Indenture, within 120 days of the end of each calendar year, an officer’s certificate as to compliance with the terms and conditions of the Debenture Indenture; and | ||
• | the Trust is prohibited from issuing additional debentures, which are convertible at the option of the holder into Trust Units of equal ranking to the Debentures if the principal amount of all issued and outstanding convertible debentures of the Trust would exceed 25 percent of the Trust’s total market capitalization after the issuance of such additional debentures. |
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• | the excess distribution or gain would be allocated ratably over the United States holder’s holding period; | ||
• | the amount allocated to the current taxable year and any year prior to the first year in which we were a PFIC would be taxed as ordinary income in the current year; | ||
• | the amount allocated to each of the other taxable years in the United States holder’s holding period would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year; and | ||
• | an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year. |
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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; |
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• | 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; | ||
• | 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; |
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• | 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 the Tax Act. Where, at the end of a month, a RRSP, RRIF, RESP or DPSP holds Trust Units that ceased to be a qualified investment, the RRSP, RRIF, RESP or DPSP, as the case may be, must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1 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 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 the Tax Act. The payment of Part XII.2 tax by the Trust may have adverse income tax consequences for certain Unitholders, including non-resident persons and residents of Canada who are exempt from Part I tax. | ||
• | The Trust would not be entitled to use the capital gains refund mechanism otherwise available for mutual fund trusts. | ||
• | The Trust Units would constitute “taxable Canadian property” for the purposes of the Tax Act, potentially subjecting non-residents of Canada to tax pursuant to the Tax Act on the disposition (or deemed disposition) of such Trust Units. |
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• | 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 | ||
• | 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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• | We have elected under applicable United States Treasury Regulations to be treated as a partnership for United States federal income tax purposes. Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”) provides that publicly-traded partnerships such as the Trust will, as a general rule, be taxed as corporations. We 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 we expect to satisfy the 90 percent requirement at all times, if we fail to satisfy this requirement, we will be treated as a foreign corporation. Such conversion will be taxable unless a certain filing is made. | ||
• | If we were treated as a foreign corporation, we could be a passive foreign investment company or “PFIC”. If we were considered a PFIC, United States holders of Trust Units could be subject to substantially increased United States tax liability, including an interest charge upon the sale or other disposition of the United States holder’s Trust Units, or upon the receipt of “excess distributions” from the Trust. Certain elections may be available to a United States holder if we were classified as a PFIC to alleviate these adverse tax consequences. | ||
• | We treat the Royalty between the Trust and the Corporation as a royalty interest for all legal purposes, including United States federal income tax purposes. The Royalty Indenture in some respects differs from more conventional “net profits” interests as to which the courts and the IRS have ruled regarding the federal income tax treatment as a royalty, and as a result the propriety of such treatment is not free from doubt. It is possible that the IRS could contend, for example, that we should be considered to have a working interest in the properties of the Corporation. If the IRS were successful in making such a contention, the United States federal income tax consequences to United States holders could be different, perhaps materially worse, than indicated in the discussion herein, which generally assumes that the Royalty Indenture will be respected as a royalty. | ||
• | Gain or loss will be recognized on a sale of Trust Units equal to the difference between the amount realized and the United States holder’s tax basis for the Trust Units sold. Gain or loss recognized by a United States holder on the sale or exchange of Trust Units will generally be taxable as capital gain or loss, and will be long-term capital gain or loss if such United States holder’s holding period of the Trust Units exceeds one year. A portion of any amount realized on a sale or exchange of Trust Units (which portion could be substantial) will be separately computed and taxed as ordinary income under Section 751 of the Code to the extent attributable to the recapture of depletion or depreciation deductions. Ordinary income attributable to depletion deductions and depreciation recapture could exceed net taxable gain realized upon the sale of the Trust Units and may be recognized even if there is a net taxable loss realized on the sale of the Trust Units. Thus, a United States holder may recognize both ordinary income and a capital loss upon a taxable disposition of Trust Units. |
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• | We have registered as a “tax shelter” with the United States Secretary of the Treasury because of the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which otherwise might be imposed if we failed to register and it were subsequently determined that registration was required. Registration as a “tax shelter” may increase the risk of an IRS audit of us or a Unitholder. 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. | ||
• | Because we cannot match transferors and transferees of Trust Units, we must maintain uniformity of the economic and tax characteristics of the Trust Units to a purchaser of these Trust Units. In the absence of such uniformity, the Trust may be unable to comply completely with a number of federal income tax requirements. A lack of uniformity, however, can result from a literal application of some Treasury regulations. If any non-uniformity was required by the IRS, it could have a negative impact on the value of the Trust Units. | ||
• | 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. Prospective purchasers of Trust Units that are tax-exempt organizations are encouraged to consult their tax advisors regarding investments in Trust Units. | ||
• | The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Trust Units may be modified by administrative, legislative or judicial interpretation at any time. For example, in response to certain recent developments, members of Congress are considering substantive changes to the existing U.S. tax laws that would affect certain publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Trust Units. | ||
• | We prorate our items of income, gain, loss and deduction between transferors and transferees of our Trust Units each month based upon the ownership of our Trust Units on the first day of each month, instead of on the basis of the date a particular Trust Unit is transferred. The use of the proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders. | ||
• | On September 21, 2007, Canada and the United States signed the Protocol to the Canada-U.S. Convention. On December 14, 2007, Canada completed the steps required to give effect to the Protocol. The Protocol will come into force once it has been ratified by the United States, and the two countries have formally notified each other that their procedures are complete. The Protocol contains new Article IV(7)(b), a treaty benefit denial rule, which would increase the Canadian withholding tax on Pengrowth’s distributions (which for the purposes of this paragraph includes deemed dividends pursuant to the SIFT Legislation) to Non-Resident Unitholders who are residents of the U.S. for the purposes of the Canada-U.S. Convention. Article IV(7)(b) of the Protocol will not come into force until the first day of the third calendar year that ends after the Protocol is in force. Article IV(7)(b) of the Protocol generally denies benefits under the Canada-U.S. Convention in circumstances where (i) a Unitholder who is a resident of the U.S. for the purposes of the Canada-U.S. Convention receives an amount, such as a distribution, from an entity that is a resident of Canada, such as Pengrowth, (ii) Pengrowth is treated as a fiscally |
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transparent entity for U.S. federal income tax purposes, which is the case inasmuch as Pengrowth is treated as a partnership for U.S. federal income tax purposes, and (iii) the tax treatment of the amount (or distribution) received by the U.S. Resident Unitholder would, for U.S. federal income tax purposes, be different if Pengrowth were not treated as fiscally transparent for U.S. federal income tax purposes. The effect of Article IV(7)(b) of the Protocol is that the Canadian withholding tax rate on distributions of income would be 25 percent instead of 15 percent or such lower rate otherwise available under the Canada-U.S. Convention. Returns of capital would still be subject to a 15 percent Canadian withholding tax and such rate is not modified by the Protocol. The Protocol also contains measures which, generally speaking, are designed to limit the benefits under the Canada-U.S. Convention to “treaty shopping” transactions or arrangements. |
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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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Toronto Stock Exchange | New York Stock Exchange | |||||||||||||||||||||||||||||||
Trust Unit Price Range | Trust Unit Price Range | |||||||||||||||||||||||||||||||
High | Low | Close | Volume | High | Low | Close | Volume | |||||||||||||||||||||||||
(Canadian $ per Trust Unit) | (thousands) | (U.S. $ per Trust Unit) | (thousands) | |||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||
January | 20.55 | 18.62 | 19.85 | 15,459 | 17.41 | 15.82 | 16.94 | 10,566 | ||||||||||||||||||||||||
February | 20.85 | 19.50 | 19.98 | 9,312 | 17.96 | 16.67 | 17.23 | 6,983 | ||||||||||||||||||||||||
March | 20.37 | 18.71 | 19.45 | 12,971 | 17.59 | 15.95 | 16.87 | 9,085 | ||||||||||||||||||||||||
April | 19.83 | 18.82 | 19.11 | 9,615 | 17.74 | 16.45 | 17.27 | 7,127 | ||||||||||||||||||||||||
May | 20.62 | 19.00 | 19.92 | 9,382 | 19.05 | 17.18 | 18.73 | 9,519 | ||||||||||||||||||||||||
June | 21.04 | 19.68 | 20.27 | 9,351 | 19.84 | 18.50 | 19.09 | 7,021 | ||||||||||||||||||||||||
July | 20.70 | 18.71 | 19.51 | 8,746 | 19.85 | 17.51 | 18.30 | 5,870 | ||||||||||||||||||||||||
August | 19.50 | 17.40 | 18.04 | 7,886 | 18.43 | 16.25 | 17.06 | 6,396 | ||||||||||||||||||||||||
September | 18.78 | 16.92 | 18.64 | 11,608 | 18.87 | 16.65 | 18.84 | 7,019 | ||||||||||||||||||||||||
October | 18.68 | 17.65 | 18.00 | 8,144 | 19.10 | 17.90 | 18.92 | 5,681 | ||||||||||||||||||||||||
November | 18.45 | 17.00 | 18.11 | 8,417 | 19.21 | 17.70 | 18.13 | 5,239 | ||||||||||||||||||||||||
December | 18.50 | 17.31 | 17.62 | 6,998 | 18.24 | 17.30 | 17.77 | 3,060 |
Toronto Stock Exchange | ||||||||||||||||
Debenture Price Range | ||||||||||||||||
High | Low | Close | Volume | |||||||||||||
(Canadian $ per Debenture) | (thousands) | |||||||||||||||
2007 | ||||||||||||||||
January | 102.49 | 98.51 | 101.01 | 1,738 | ||||||||||||
February | 102.25 | 101.00 | 101.25 | 828 | ||||||||||||
March | 102.55 | 100.00 | 100.51 | 767 | ||||||||||||
April | 102.55 | 99.77 | 102.00 | 661 | ||||||||||||
May | 104.00 | 100.60 | 101.10 | 279 | ||||||||||||
June | 102.50 | 100.00 | 100.51 | 494 | ||||||||||||
July | 102.99 | 100.03 | 100.04 | 327 | ||||||||||||
August | 100.02 | 98.00 | 99.50 | 590 | ||||||||||||
September | 99.75 | 98.50 | 99.00 | 560 | ||||||||||||
October | 100.80 | 99.00 | 99.75 | 518 | ||||||||||||
November | 101.00 | 98.50 | 99.50 | 633 | ||||||||||||
December | 102.89 | 98.00 | 100.00 | 1,149.3 |
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Name and Jurisdiction | Position with | |||
of Residence | Pengrowth Management | Principal Occupation | ||
James S. Kinnear | President and Director (since 1982) | President | ||
Alberta, Canada | Pengrowth Management Limited | |||
Gordon M. Anderson | Vice President, Financial Services (since 2001) | Vice President, Financial Services | ||
Alberta, Canada | Vice President, Treasurer (1998-2001) | Pengrowth Management Limited | ||
Treasurer (1995-1998) | ||||
Grant A. Henschel | Vice President, Engineering | Vice President, Engineering | ||
Alberta, Canada | Pengrowth Management Limited | |||
Leslie F. Kende | Vice President, New Ventures | Vice President, New Ventures | ||
Alberta, Canada | Pengrowth Management Limited | |||
Robert M. Nicolay | Vice President, Business Development | Vice President, Business Development | ||
Alberta, Canada | Pengrowth Management Limited | |||
Charles V. Selby | Corporate Secretary (since 1993) | President | ||
Alberta, Canada | Treasurer | Selby Professional Corporation |
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Trust Units | ||||||||
Controlled or | ||||||||
Name and Jurisdiction | Position with | Beneficially | ||||||
of Residence | Pengrowth Corporation | Principal Occupation | Owned(1) | |||||
James S. Kinnear | President, Chairman, Director and | President | 5,996,238 | |||||
Alberta, Canada | Chief Executive Office (since 1988) | Pengrowth Management Limited | ||||||
Thomas A. Cumming(2)(4)(5) | Director (since 2000) | Business Consultant | 8,678 | |||||
Alberta, Canada | ||||||||
Wayne K. Foo(2)(3) | Director (since 2006) | �� | President | 3,843 | ||||
Alberta, Canada | Petro Andina Resources Ind. | |||||||
Kirby L. Hedrick(2)(5) | Director (since 2005) | Business Consultant | 4,000 | |||||
Wyoming, United States of America | ||||||||
Michael S. Parrett(3)(4)(5) | Director (since 2004) | Business Consultant | 4,000 | |||||
Ontario, Canada | ||||||||
A. Terence Poole(3)(5) | Director (since 2005) | Business Consultant | 30,000 | |||||
Alberta, Canada | ||||||||
D. Michael G. Stewart(2)(4) | Director (since 2006) | Principal of the Ballinacurra | 13,370 | |||||
Alberta, Canada | Group, Corporate Director | |||||||
Nicholas C.H. Villiers | Director (since 2007) | Business Consultant | — | |||||
London, England | ||||||||
John B. Zaozirny(3)(4) | Director (since 1988) | Counsel, McCarthy Tétrault | 35,100 | |||||
Alberta, Canada | Barristers and Solicitors | |||||||
Gordon M. Anderson | Vice President (since 2001) | Vice President, Financial | 21,066 | |||||
Alberta, Canada | Vice President, Treasurer (1997-2001) | Services Pengrowth Management | ||||||
Treasurer (1995-1997) | Limited | |||||||
Chief Financial Officer (1991-1998) | ||||||||
Douglas C. Bowles | Vice President and Controller | Vice President and Controller | 11,446 | |||||
Alberta, Canada | (since March 1, 2006) | Pengrowth Corporation | ||||||
Controller (since 2005) | ||||||||
James E.A. Causgrove | Vice President, Production and | Vice President, Production | 23,621 | |||||
Alberta, Canada | Operations (since 2005) | and Operations Pengrowth Corporation | ||||||
Peter Cheung | Vice President (since 2008) | Vice President and Treasurer | 17,428 | |||||
Alberta, Canada | Treasurer (since 2005) | Pengrowth Corporation | ||||||
William G. Christensen | Vice President, Strategic Planning and | Vice President, Strategic | 15,821 | |||||
Alberta, Canada | Reservoir Exploitation (since 2005) | Planning and Reservoir Exploitation Pengrowth Corporation | ||||||
James M. Donihee | Vice-President and Chief of Staff | Vice-President and Chief of | 7,086 | |||||
Alberta, Canada | (since 2007) | Staff Pengrowth Corporation | ||||||
Charles V. Selby | Vice President and Corporate Secretary | President | 146,916 | |||||
Alberta, Canada | (since 2005) | Selby Professional Corporation | ||||||
Corporate Secretary (since 1993) | ||||||||
Larry B. Strong | Vice President, Geosciences (since 2005) | Vice President, Geosciences | 37,118 | |||||
Alberta, Canada | Pengrowth Corporation | |||||||
Christopher G. Webster | Chief Financial Officer (since 2005) | Chief Financial Officer | 37,065 | |||||
Alberta, Canada | Treasurer (2000 — 2005) | Pengrowth Corporation |
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Notes: | ||
(1) | As at December 31, 2007 and excluding Trust Units issuable upon the exercise of outstanding options, rights or deferred entitlement units. | |
(2) | Member of Reserves, Operations and Environmental, Health and Safety Committee. | |
(3) | Member of Corporate Governance Committee. | |
(4) | Member of Compensation Committee. | |
(5) | Member of Audit Committee. |
(i) | was the subject of a cease trade or similar order or an order that denied the relevant company 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 company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or |
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(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. |
(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 penalties for late filing of insider reports; 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 Alberta Capital Market Foundation. He is also a past president of the Calgary Chamber of Commerce. Mr. Cumming is a professional engineer and holds a Bachelor of Applied Science degree in Engineering and Business from the University of Toronto. | |||
Michael S. Parrett | Yes | Yes | Mr. Parrett is currently an independent consultant providing advisory service to various companies in Canada and the United States. Mr. Parrett is Chairman of Gabriel Resources Limited, a member of the board of Fording Inc. and is serving as a Trustee for Fording Canadian Coal Trust. He was formerly 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 brings extensive senior financial management, accounting, capital and debt market experience to Pengrowth. He retired from Nova Chemicals Corporation in 2006 where he had held various senior management positions including Executive Vice-President, Corporate Strategy and Development. Mr. Poole currently serves on the board of directors for Methanex Corporation and Synenco Energy Inc. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Accountant designation. |
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Financially | ||||||
Name | Independent | Literate | Relevant Education and Experience | |||
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 directors of Noble Energy Inc. and has recently been appointed to the Wyoming Environmental Quality Council. 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. |
2007 | 2006 | |||||||
Audit Fees | 1,393 | 980 | ||||||
Audit Related Fees | — | — | ||||||
Tax Fees | 163 | 138 | ||||||
All Other Fees | — | — | ||||||
Total | 1,556 | 1,118 |
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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; | |
4. | Management Agreement; | |
5. | the Fifth Amended and Restated Credit Agreement dated June 17, 2007 between Pengrowth and a syndicate of eleven financial institutions concerning the Credit Facility; | |
6. | the Bridge Credit Agreement dated January 22, 2007 between Pengrowth and a syndicate of ten financial institutions entered into in conjunction with the CP Acquisition; | |
7. | the Acquisition Agreement dated November 28, 2006 in connection with the CP Acquisition; | |
8. | the Note Purchase Agreement dated July 26, 2007 concerning the 2007 U.S. Senior Notes; | |
9 | the Note Purchase Agreement dated April 23, 2003 concerning the 2003 U.S. Senior Notes; | |
10. | the Note Purchase Agreement dated December 1, 2005 concerning the U.K. Senior Notes; | |
11. | the Debenture Indenture; | |
12. | the first supplemental trust indenture relating to the Debentures dated October 2, 2006; and |
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12. | the Distribution Agreement. |
OF THE NEW YORK STOCK EXCHANGE
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Investor Relations | Toronto Investor Relations | |
Pengrowth Energy Trust | Scotia Plaza, 40 King Street West | |
Suite 2100, 222 – 3rd Avenue S.W. | Suite 3006, Box 106 | |
Calgary, Alberta T2P 0B4 | Toronto, Ontario M5H 3Y2 | |
Telephone: (403) 233-0224 | Telephone: (416) 362-1748 | |
(888) 744-1111 | (888) 744-1111 | |
Fax: (866) 341-3586 |
E-mail:investorrelations@pengrowth.com
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REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
1. | We have prepared an evaluation of the Company’s reserves data as at December 31, 2007. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs. | |
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, 2007, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors: |
Description and | ||||||||||||
Preparation Date | Location of Reserves | Net Present Value of Future Net Revenue | ||||||||||
Independent Qualified | of Evaluation | (Country or Foreign | (before income taxes, 10% discount rate - $MM) | |||||||||
Reserves Evaluator | Report | Geographic Area) | Audited | Evaluated | Reviewed | Total | ||||||
GLJ Petroleum Consultants | January 15, 2008 | Canada | — | $5,456 | — | $5,456 |
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 judgments regarding future events, actual results will vary and the variations may be material. |
(signed)“Doug R. Sutton” | ||
Vice-President |
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REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
(a) | reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator; | |
(b) | met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and | |
(c) | reviewed the reserves data with management and the independent qualified reserves evaluator. |
(a) | the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; | |
(b) | the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and | |
(c) | the content and filing of this report. |
(signed) “James S. Kinnear” | ||
Chairman, President and Chief Executive Officer | ||
Pengrowth Corporation | ||
(signed) “William G. Christensen” | ||
Vice President, Strategic Planning and Reservoir Exploitation | ||
Pengrowth Corporation | ||
(signed) “Kirby L. Hedrick” Director | ||
Pengrowth Corporation | ||
(signed) “D. Michael G. Stewart” | ||
Director | ||
Pengrowth Corporation |
March 19, 2008
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AUDIT COMMITTEE
PENGROWTH ENERGY TRUST
• | monitor the performance of Pengrowth’s internal audit function and the integrity of Pengrowth’s financial reporting process and systems of internal controls regarding finance, accounting, and legal compliance; | ||
• | assist Board oversight of: (i) the integrity of Pengrowth’s financial statements; (ii) Pengrowth’s compliance with legal and regulatory requirements; and (iii) the performance of Pengrowth’s internal audit function and independent auditors; | ||
• | monitor the independence, qualification and performance of Pengrowth’s external auditors; and | ||
• | provide an avenue of communication among the external auditors, the internal auditors, management and the Board. |
1. | Review and reassess the adequacy of the Audit Committee’s Terms of Reference at least annually, submit the Terms of Reference to the Board for approval and have the document published at least every three years in accordance with the regulations of the United States’ Securities and Exchange Commission. |
2. | Prior to filing or public distribution, review, discuss with management and the internal and external auditors and recommend to the Board for approval, Pengrowth’s audited annual financial statements, annual earnings press releases, annual information form, all statements including the related management’s discussion and analysis required in prospectuses and other offering memoranda, financial statements required by regulatory authorities, all prospectuses and all documents which may be incorporated by reference into a prospectus, including without limitation, the annual proxy circular. Approve, on behalf of the Board, Pengrowth’s interim financial statements and related management’s discussion and analysis and interim earnings press releases. This review should include discussions with management, the internal auditors and the external auditors of significant issues regarding accounting principles, practices and judgements. Discuss any significant changes to Pengrowth’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). | |
3. | Ensure that adequate procedures are in place for the review of Pengrowth’s public disclosure of financial information extracted or derived from Pengrowth’s financial statements, other than the |
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public disclosure referred to in paragraph 2 above and periodically assess the adequacy of those procedures. | ||
4. | Be responsible for reviewing the disclosure contained in Pengrowth’s annual information form as required by Form 52-110F1 Audit Committee Information Required in an AIF, attached to MI 52-110. If proxies are solicited for the election or directors of the Corporation, the Audit Committee shall be responsible for ensuring that Pengrowth’s information circular includes a cross-reference to the sections in Pengrowth’s annual information form that contain the information required by Form 52-110F1. |
1. | The Audit Committee shall advise the external auditors of their accountability to the Audit Committee and the Board as representatives of the unitholders of the Trust to whom the external auditors are ultimately responsible. The external auditors shall report directly to the Audit Committee. The Audit Committee is directly responsible for overseeing the work of the external auditors, shall review at least annually the independence and performance of the external auditors and shall annually recommend to the Board 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 external auditor’s internal quality-control procedures; (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with any such issues; and (iii) all relationships between the independent auditor and Pengrowth. |
3. | Pre-approve all services to be provided to Pengrowth or its subsidiary entities by Pengrowth’s external auditors and all related terms of engagement. |
4. | Establish procedures for: (i) the receipt, retention and treatment of complaints received by Pengrowth regarding accounting, internal accounting controls, or auditing matters; and (ii) the confidential and anonymous submission by employees of Pengrowth of concerns regarding questionable accounting or auditing matters. |
5. | Review and approve Pengrowth’s hiring policies regarding partners, employees and former partners and employees of the present and former external auditors of Pengrowth. |
1. | In consultation with management, the internal auditors and the external auditors, consider the integrity of Pengrowth’s financial reporting processes and controls and the performance of Pengrowth’s internal financial accounting staff; discuss significant financial risk exposures and the steps management has taken to monitor, control and report such exposures; and review significant findings prepared by the internal or external auditors together with management’s responses. |
2. | Review with financial management, the internal auditors and the external auditors Pengrowth’s policies relating to risk management and risk assessment. |
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3. | Meet separately with each of management, the internal auditors and 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 on such meetings. |
1. | Review the annual audit plans of the internal auditors. |
2. | 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. |
3. | Review the adequacy of the resources of the internal auditors to ensure the objectivity and independence of the internal audit function. |
4. | Consult with management on management’s appointment, replacement, reassignment or dismissal of the internal auditors. |
5. | Ensure that the internal auditors have access to the Lead Director, the Chair of the Board and the Chief Executive Officer. |
1. | On an annual basis, the Audit Committee should review and discuss with the external auditors all significant relationships they have with Pengrowth that could impair the auditors’ independence. |
2. | The Audit Committee shall review the external auditors audit plan – discuss scope, staffing, locations, and reliance upon management and general audit approach. |
3. | Consider the external auditors’ judgments about the quality and appropriateness of Pengrowth’s accounting principles as applied in its financial reporting. |
4. | Be responsible for the resolution of disagreements between management and the external auditors regarding financial performance. |
5. | Ensure compliance by the external auditors with the requirements set forth in National Instrument 52-108Auditor Oversight. |
6. | Ensure that the external auditors are participants in good standing with the Canadian Public Accountability Board (“CPAB”) and participate in the oversight programs established by the CPAB from time to time and that the external auditors have complied with any restrictions or sanctions imposed by the CPAB as of the date of the applicable auditor’s report relating to Pengrowth’s annual audited financial statements. |
1. | On at least an annual basis, review with Pengrowth’s counsel any legal matters that could have a significant impact on the organization’s financial statements, Pengrowth’s compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies. |
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2. | Annually prepare a report to unitholders as required by the United States’ Securities and Exchange Commission; the report should be included in Pengrowth’s annual proxy statement. |
3. | Ensure the preparation and filing of each annual certificate in Form 52-109F1 and each interim certificate in Form 52-109F2 to be signed by each of the Chief Executive Officer and Chief Financial Officer of the Corporation in accordance with the requirements set forth under Multilateral Instrument 52-109Certification of Disclosure in Issuers’ Annual and Interim Filings, as amended from time to time (“MI 52-109”). |
4. | In respect of annual filings only, the Audit Committee is responsible for ensuring that management evaluates the effectiveness of Pengrowth’s disclosure controls and procedures as of the end of the period covered by the annual filings and has caused Pengrowth to disclose in the annual management’s discussion and analysis its conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by the annual filings based on such evaluation. The terms “annual filings,” “interim filings,” “disclosure controls and procedures” and “internal control over financial reporting” shall have the meanings set forth under MI 52-109. |
5. | Be responsible for monitoring any changes in Pengrowth’s internal control over financial reporting and for ensuring that any change that occurred during Pengrowth’s most recent interim period that has materially affected, or is reasonably likely to materially affect, Pengrowth’s internal control over financial reporting is disclosed in Pengrowth’s most recent annual or interim management’s discussion and analysis. |
6. | Review all exceptions to established policies, procedures and internal controls of Pengrowth, which have been approved by any two officers of the Corporation. |
7. | Perform any other activities consistent with this Charter, the Trust Indenture, the Corporation’s by-laws, and other governing law as the Audit Committee or the Board deems necessary or appropriate. |
8. | Maintain minutes of meetings and periodically report to the Board on significant results of the foregoing activities. |
A-1
1. | An audit committee member is independent if he or she has no direct or indirect material relationship with Pengrowth. |
2. | For the purposes of paragraph 1, a “material relationship” is a relationship which could, in the view of the Board, be reasonably expected to interfere with the exercise of a member’s independent judgment. |
3. | Despite paragraph 2, the following individuals are considered to have a material relationship with Pengrowth: |
(a) | an individual who is, or has been within the last three years, an employee or executive officer of Pengrowth; | ||
(b) | an individual whose immediate family member is, or has been within the last three years, an executive officer of Pengrowth; | ||
(c) | an individual who: |
(i) | is a partner of a firm that is Pengrowth’s internal or external auditor, | ||
(ii) | is an employee of that firm, or | ||
(iii) | was within the last three years a partner or employee of that firm and personally worked on Pengrowth’s audit within that time; |
(d) | an individual whose spouse, minor child or stepchild, or child or stepchild who shares a home with the individual: |
(i) | is a partner of a firm that is Pengrowth’s internal or external auditor, | ||
(ii) | is an employee of that firm and participates in its audit, assurance or tax compliance (but not tax planning) practice, or | ||
(iii) | was within the last three years a partner or employee of that firm and personally worked on Pengrowth’s audit within that time; |
(e) | an individual who, or whose immediate family member, is or has been within the last three years, an executive officer of an entity if any of Pengrowth’s current executive officers serves or served at that same time on the entity’s compensation committee; and | ||
(f) | an individual who received, or whose immediate family member who is employed as an executive officer of Pengrowth received, more than $75,000 in direct compensation from the issuer during any 12 month period within the last three years. |
4. | Despite paragraph 3, an individual will not be considered to have a material relationship with Pengrowth solely because he or she had a relationship identified in paragraph 3 if that relationship ended before March 30, 2004. |
5. | For the purposes of paragraphs 3(c) and 3(d), a partner does not include a fixed income partner whose interest in the firm that is the internal or external auditor is limited to the receipt of fixed |
A-2
compensation (including deferred compensation) for prior service with that firm if the compensation is not contingent in any way on continued service. |
6. | For the purposes of paragraph 3(f), direct compensation does not include |
(a) | remuneration for acting as a member of the Board or any Board committee of Pengrowth, and | ||
(b) | the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with Pengrowth if the compensation is not contingent in any way on continued service. |
7. | Despite paragraph 3, an individual will not be considered to have a material relationship with Pengrowth solely because the individual or his or her immediate family member |
(a) | has previously acted as an interim chief executive officer of Pengrowth, or | ||
(b) | acts, or has previously acted, as a chair or vice-chair of the Board or of any Board committee of Pengrowth on a part-time basis. |
8. | Despite any determination made under paragraphs 1 through 7, an individual who |
(a) | accepts, directly or indirectly, any consulting, advisory or other compensatory fee from Pengrowth, other than as remuneration for acting in his or her capacity as a member of the Board or any Board committee, or as a part-time chair or vice-chair of the Board or any Board committee; or | ||
(b) | is an affiliated entity of Pengrowth or any of its subsidiary entities, is considered to have a material relationship with Pengrowth. |
9. | For the purposes of paragraph 8, the indirect acceptance by an individual of any consulting, advisory or other compensatory fee includes acceptance of a fee by |
(a) | an individual’s spouse, minor child or stepchild, or a child or stepchild who shares the individual’s home; or | ||
(b) | an entity in which such individual is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to Pengrowth. |
10. | For the purposes of paragraph 8, compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with Pengrowth if the compensation is not contingent in any way on continued service. |
B-1
b. | Required standards. | |
1. | Independence. |
i. | Each member of the audit committee must be a member of the board of directors of the listed issuer, and must otherwise be independent; provided that, where a listed issuer is one of two dual holding companies, those companies may designate one audit committee for both companies so long as each member of the audit committee is a member of the board of directors of at least one of such dual holding companies. | ||
ii. | Independence requirements for non-investment company issuers. In order to be considered to be independent for purposes of this paragraph (b)(1), a member of an audit committee of a listed issuer that is not an investment company may not, other than in his or her capacity as a member of the audit committee, the board of directors, or any other board committee: |
A. | Accept directly or indirectly any consulting, advisory, or other compensatory fee from the issuer or any subsidiary thereof, provided that, unless the rules of the national securities exchange or national securities association provide otherwise, compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the listed issuer (provided that such compensation is not contingent in any way on continued service); or | ||
B. | Be an affiliated person of the issuer or any subsidiary thereof. |
e. | Definitions. Unless the context otherwise requires, all terms used in this section have the same meaning as in the Act. In addition, unless the context otherwise requires, the following definitions apply for purposes of this section: | |
1. |
i. | The termaffiliateof, or a personaffiliatedwith, a specified person, means a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the person specified. | ||
ii. |
A. | A person will be deemed not to be in control of a specified person for purposes of this section if the person: |
1. | Is not the beneficial owner, directly or indirectly, of more than 10% of any class of voting equity securities of the specified person; and (2) Is not an executive officer of the specified person. |
B. | Paragraph (e)(1)(ii)(A) of this section only creates a safe harbor position that a person does not control a specified person. The existence of the safe harbor does not create a presumption in any way that a person exceeding the ownership requirement in paragraph (e)(1)(ii)(A)(1) of this section controls or is otherwise an affiliate of a specified person. |
B-2
iii. | The following will be deemed to be affiliates: |
A. | An executive officer of an affiliate; | ||
B. | A director who also is an employee of an affiliate; | ||
C. | A general partner of an affiliate; and | ||
D. | A managing member of an affiliate. |
iv. | For purposes of paragraph (e)(1)(i) of this section, dual holding companies will not be deemed to be affiliates of or persons affiliated with each other by virtue of their dual holding company arrangements with each other, including where directors of one dual holding company are also directors of the other dual holding company, or where directors of one or both dual holding companies are also directors of the businesses jointly controlled, directly or indirectly, by the dual holding companies (and, in each case, receive only ordinary-course compensation for serving as a member of the board of directors, audit committee or any other board committee of the dual holding companies or any entity that is jointly controlled, directly or indirectly, by the dual holding companies). |
4. | The term control (including the terms controlling, controlled by and under common control with) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person, whether through the ownership of voting securities, by contract, or otherwise. | |
8. | The term indirect acceptance by a member of an audit committee of any consulting, advisory or other compensatory fee includes acceptance of such a fee by a spouse, a minor child or stepchild or a child or stepchild sharing a home with the member or by an entity in which such member is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to the issuer or any subsidiary of the issuer. |
C-1
(a) | No director qualifies as “independent” unless the board of directors affirmatively determines that the director has no material relationship with the listed company (either directly or as a partner, shareholder or officer of an organization that has a relationship with the company). Companies must identify which directors are independent and disclose the basis for that determination. | ||
(b) | In addition, a director is not independent if: |
(i) | The director is, or has been within the last three years, an employee of the listed company, or an immediate family member is, or has been within the last three years, an executive officer, of the listed company. | ||
(ii) | The director has received, or has an immediate family member who has received, during any twelve-month period within the last three years, more than $100,000 in direct compensation from the listed company, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service). | ||
(iii) | (A) The director or an immediate family member is a current partner of a firm that is the company’s internal or external auditor; (B) the director is a current employee of such a firm; (C) the director has an immediate family member who is a current employee of such a firm and who participates in the firm’s audit, assurance or tax compliance (but not tax planning) practice; or (D) the director or an immediate family member was within the last three years (but is no longer) a partner or employee of such a firm and personally worked on the listed company’s audit within that time. | ||
(iv) | The director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of the listed company’s present executive officers at the same time serves or served on that company’s compensation committee. | ||
(v) | The director is a current employee, or an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, the listed company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1 million, or 2% of such other company’s consolidated gross revenues. |
C-2
(thousands, | Three Months ended December 31 | Twelve Months ended December 31 | |||||||||||||||||||||||||||
except per unit amounts) | 2007 | 2006 | % Change | 2007 | 2006 | % Change | |||||||||||||||||||||||
INCOME STATEMENT | |||||||||||||||||||||||||||||
Oil and gas sales | $ | 425,249 | $ | 350,908 | 21 | $ | 1,722,038 | $ | 1,214,093 | 42 | |||||||||||||||||||
Net income | $ | (3,665 | ) | $ | 3,310 | (211 | ) | $ | 359,652 | $ | 262,303 | 37 | |||||||||||||||||
Net income per trust unit | $ | (0.01 | ) | $ | 0.01 | (200 | ) | $ | 1.47 | $ | 1.49 | (1 | ) | ||||||||||||||||
CASH FLOW | |||||||||||||||||||||||||||||
Cash flows from operating activities | $ | 196,325 | $ | 91,237 | 115 | $ | 800,344 | $ | 554,368 | 44 | |||||||||||||||||||
Cash flows from operating activities per trust unit | $ | 0.80 | $ | 0.41 | 95 | $ | 3.26 | $ | 3.15 | 3 | |||||||||||||||||||
Distributions declared | $ | 166,631 | $ | 185,651 | (10 | ) | $ | 706,601 | $ | 559,063 | 26 | ||||||||||||||||||
Distributions declared per trust unit | $ | 0.675 | $ | 0.75 | (10 | ) | $ | 2.875 | $ | 3.00 | (4 | ) | |||||||||||||||||
Ratio of distributions declared over cash flows from operating activities | 85 | % | 203 | % | 88 | % | 101 | % | |||||||||||||||||||||
Capital expenditures | $ | 95,743 | $ | 121,781 | (21 | ) | $ | 309,708 | $ | 300,809 | 3 | ||||||||||||||||||
Capital expenditures per trust unit | $ | 0.39 | $ | 0.55 | (29 | ) | $ | 1.26 | $ | 1.71 | (26 | ) | |||||||||||||||||
BALANCE SHEET | |||||||||||||||||||||||||||||
Working capital(1) | $ | (189,603 | ) | $ | (160,949 | ) | 18 | ||||||||||||||||||||||
Property, plant and equipment | $ | 4,306,682 | $ | 3,741,602 | 15 | ||||||||||||||||||||||||
Long term debt | $ | 1,203,236 | $ | 604,200 | 99 | ||||||||||||||||||||||||
Trust unitholders’ equity | $ | 2,756,220 | $ | 3,049,677 | (10 | ) | |||||||||||||||||||||||
Trust unitholders’ equity per trust unit | $ | 11.17 | $ | 12.50 | (11 | ) | |||||||||||||||||||||||
Currency (U.S.$/Cdn$) (closing rate at period end) | 1.0088 | 0.8581 | |||||||||||||||||||||||||||
Weighted average number of trust units outstanding | 246,513 | 220,734 | 12 | 245,470 | 175,871 | 40 | |||||||||||||||||||||||
Number of trust units outstanding at period end | 246,846 | 244,017 | 1 | ||||||||||||||||||||||||||
(1) | Prior year restated to conform to presentation adopted in current year |
Three Months ended December 31 | Twelve Months ended December 31 | ||||||||||||||||||||||||||||
2007 | 2006 | % Change | 2007 | 2006 | % Change | ||||||||||||||||||||||||
AVERAGE DAILY PRODUCTION | |||||||||||||||||||||||||||||
Crude oil (barrels) | 25,892 | 25,000 | 4 | 26,327 | 21,821 | 21 | |||||||||||||||||||||||
Heavy oil (barrels) | 7,434 | 4,695 | 58 | 7,168 | 4,964 | 44 | |||||||||||||||||||||||
Natural gas (mcf) | 250,117 | 234,050 | 7 | 266,980 | 175,578 | 52 | |||||||||||||||||||||||
Natural gas liquids (barrels) | 9,319 | 8,910 | 5 | 9,409 | 6,774 | 39 | |||||||||||||||||||||||
Total production (boe) | 84,331 | 77,614 | 9 | 87,401 | 62,821 | 39 | |||||||||||||||||||||||
TOTAL PRODUCTION (mboe) | 7,758 | 7,141 | 9 | 31,901 | 22,930 | 39 | |||||||||||||||||||||||
PRODUCTION PROFILE | |||||||||||||||||||||||||||||
Crude oil | 31 | % | 32 | % | 30 | % | 35 | % | |||||||||||||||||||||
Heavy oil | 9 | % | 6 | % | 8 | % | 8 | % | |||||||||||||||||||||
Natural gas | 49 | % | 50 | % | 51 | % | 46 | % | |||||||||||||||||||||
Natural gas liquids | 11 | % | 12 | % | 11 | % | 11 | % | |||||||||||||||||||||
AVERAGE REALIZED PRICES (after commodity risk management) | |||||||||||||||||||||||||||||
Crude oil (per barrel) | $ | 73.69 | $ | 60.35 | 22 | $ | 71.88 | $ | 66.85 | 8 | |||||||||||||||||||
Heavy oil (per barrel) | $ | 45.47 | $ | 37.61 | 21 | $ | 44.53 | $ | 42.26 | 5 | |||||||||||||||||||
Natural gas (per mcf) | $ | 6.90 | $ | 7.12 | (3 | ) | $ | 7.29 | $ | 7.22 | 1 | ||||||||||||||||||
Natural gas liquids (per barrel) | $ | 67.64 | $ | 52.69 | 28 | $ | 58.86 | $ | 57.11 | 3 | |||||||||||||||||||
Average realized price per boe | $ | 54.58 | $ | 49.24 | 11 | $ | 53.90 | $ | 52.88 | 2 | |||||||||||||||||||
PROVED PLUS PROBABLE RESERVES | |||||||||||||||||||||||||||||
Crude oil (mbbls) | 124,188 | 112,388 | 10 | ||||||||||||||||||||||||||
Heavy oil (mbbls) | 21,792 | 18,336 | 19 | ||||||||||||||||||||||||||
Natural gas (bcf) | 870 | 827 | 5 | ||||||||||||||||||||||||||
Natural gas liquids (mbbls) | 28,994 | 29,142 | (1 | ) | |||||||||||||||||||||||||
Total oil equivalent (mboe) | 319,921 | 297,774 | 7 | ||||||||||||||||||||||||||
SUMMARY OF TRUST UNIT TRADING | |||||||||||||||||||||||||||||
NYSE — PGH ($U.S.) | |||||||||||||||||||||||||||||
High | $ | 19.21 | $ | 20.25 | $ | 19.85 | $ | 25.15 | |||||||||||||||||||||
Low | $ | 17.30 | $ | 14.78 | $ | 15.82 | $ | 14.78 | |||||||||||||||||||||
Close | $ | 17.77 | $ | 17.21 | $ | 17.77 | $ | 17.21 | |||||||||||||||||||||
TSX — PGF.UN ($Cdn)(1) | |||||||||||||||||||||||||||||
High | $ | 18.68 | $ | 22.69 | $ | 21.04 | $ | 26.11 | |||||||||||||||||||||
Low | $ | 17.00 | $ | 16.81 | $ | 16.92 | $ | 16.81 | |||||||||||||||||||||
Close | $ | 17.62 | $ | 19.94 | $ | 17.62 | $ | 19.94 | |||||||||||||||||||||
(1) | July 27, 2006, Pengrowth’s Class A trust units and Class B trust units were consolidated into a single class of trust units (with the exception of Class A trust units held by residents of Canada who provided an election), the Class A trust units were delisted from the Toronto Stock Exchange and the Class B trust units were renamed as Trust units and their trading symbol changed to PGF.UN |
• | Oil and gas sales increased 42 percent to $1.7 billion dollars in 2007 due to higher production volumes and higher average realized prices. In the fourth quarter, oil and gas sales were $425 million, an increase of one percent from the third quarter and 21 percent from the same quarter in 2006. |
• | Production for 2007 averaged 87,401 barrels of oil equivalent (boe) per day, a 39 percent increase over 2006. The increase is primarily due to a full year of production from the Esprit and Carson Creek acquisitions, and production from the CP properties after the January 22, 2007 closing. Fourth quarter production averaged 84,331 boe per day, virtually unchanged from the third quarter and an increase of nine percent from the fourth quarter in 2006. The higher production levels compared to the prior year reflect the CP properties acquisition and development activities, partially offset by natural production declines and divestment activities. |
• | Cash flows from operating activities in 2007 increased from the prior year by 44 percent to $800.3 million reflecting the higher production and sales prices. Fourth quarter cash flows from operating activities was $196.3 million, representing a decrease of 10 percent from the third quarter and an increase of 115 percent from the fourth quarter in 2006. The decrease from the third quarter is mainly as a result of higher operating, royalty, administrative and interest costs incurred. The 115 percent increase in the fourth quarter of 2007 from the fourth quarter in 2006 is primarily due to higher production volumes, higher realized prices and the unfavourable impact on working capital in the prior year. |
• | Distributions declared to unitholders reached an all time high of $706.6 million, an increase of 26 percent when compared to $559.1 million in 2006. For the full year in 2007, distribution declared totaled $2.875 per trust unit. Distributions declared to unitholders totaled 88 percent of its cash flows from operating activities and 85 percent in the fourth quarter. |
• | During 2007, Pengrowth closed a U.S. $400 million offering of notes issued on a private placement basis at an interest rate of 6.35 percent due in 2017. |
• | Net income increased 37 percent to $359.7 million for 2007 compared to 2006. The increase was due to higher oil and gas sales, partly offset by higher royalties, operating expenses and general and administrative costs. In addition to the above cash items, net income was significantly effected by certain non-cash items including a $296.6 million increase in depletion, depreciation and accretion expenses, and $122.3 million of unrealized commodity risk management losses, offset by $264.6 million future tax recovery recorded in 2007 due to the enactment of the previously announced tax on income trusts, asset dispositions during the second half of 2007 and a reduction in the federal income tax rate. |
• | During 2007, Pengrowth’s average realized price was $53.90 per boe (after commodity risk management) compared to an average price of $52.88 per boe in 2006. Prices for liquids were higher year over year while there was a decrease in natural gas prices. For the fourth quarter, average realized prices were $54.58 per boe (after commodity risk management) up two percent from the third quarter and 11 percent from the same quarter last year. These increases largely reflect a higher commodity price environment for oil and natural gas liquids (NGLs) while natural gas has remained relatively stable in the fourth quarter of 2007. |
• | Operating netbacks (after commodity risk management) increased three percent in 2007 to $30.40 per boe, largely driven by higher realized prices partially offset by higher operating costs. For the fourth quarter, operating netbacks were $29.56 per boe down from the previous quarter by nine percent and an increase of 22 percent from the fourth quarter of 2006. The fourth quarter netbacks were lower than the third quarter largely due to higher operating costs and royalties. |
• | Pengrowth’s development capital, excluding acquisitions, in 2007 totaled $283 million, resulting in a finding and development cost of $17.44 per boe, including future development costs. Including acquisitions, Pengrowth replaced 169 percent of its production on a proved plus probable basis at a cost of $18.97 per boe, including future development costs. During the year, Pengrowth participated in 511 gross (175 net) wells with a 97 percent success rate. |
• | Pengrowth completed asset sales for proceeds of $476 million ($459 million net of adjustments) in 2007. The assets disposed were non-core assets identified following the acquisitions of the CP properties and Esprit Trust. |
Three months ended | Twelve months ended | ||||||||||||||||||||||||
Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | |||||||||||||||||||||
Light crude oil (bbls per day) | 25,892 | 24,903 | 25,000 | 26,327 | 21,821 | ||||||||||||||||||||
Heavy oil (bbls per day) | 7,434 | 7,205 | 4,695 | 7,168 | 4,964 | ||||||||||||||||||||
Natural gas (mcf per day) | 250,117 | 261,976 | 234,050 | 266,980 | 175,578 | ||||||||||||||||||||
Natural gas liquids (bbls per day) | 9,319 | 9,883 | 8,910 | 9,409 | 6,774 | ||||||||||||||||||||
Total (boe per day) | 84,331 | 85,654 | 77,614 | 87,401 | 62,821 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | |||||||||||||||||||||
Light crude oil (per bbl) | 82.31 | 76.87 | 60.94 | 72.93 | 68.83 | ||||||||||||||||||||
after realized commodity risk management | 73.69 | 75.10 | 60.35 | 71.88 | 66.85 | ||||||||||||||||||||
Heavy oil (per bbl) | 45.47 | 47.30 | 37.61 | 44.53 | 42.26 | ||||||||||||||||||||
Natural gas (per mcf) | 6.20 | 5.54 | 6.82 | 6.71 | 7.08 | ||||||||||||||||||||
after realized commodity risk management | 6.90 | 6.67 | 7.12 | 7.29 | 7.22 | ||||||||||||||||||||
Natural gas liquids (per bbl) | 67.64 | 61.69 | 52.69 | 58.86 | 57.11 | ||||||||||||||||||||
Total per boe | 55.16 | 50.40 | 48.52 | 52.46 | 53.18 | ||||||||||||||||||||
after realized commodity risk management | 54.58 | 53.34 | 49.24 | 53.90 | 52.88 | ||||||||||||||||||||
BENCHMARK PRICES | |||||||||||||||||||||||||
WTI oil (U.S.$ per bbl) | 90.71 | 75.25 | 60.17 | 72.12 | 66.25 | ||||||||||||||||||||
AECO spot gas (Cdn$ per gj) | 5.69 | 5.32 | 6.36 | 6.27 | 6.70 | ||||||||||||||||||||
NYMEX gas (U.S.$ per mmbtu) | 6.97 | 6.16 | 6.56 | 6.86 | 7.24 | ||||||||||||||||||||
Currency (U.S. $/Cdn$) | 1.02 | 0.96 | 0.88 | 0.93 | 0.88 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | |||||||||||||||||||||
Light crude oil ($ millions) | (20.5 | ) | (4.1 | ) | (1.4 | ) | (10.1 | ) | (15.8 | ) | |||||||||||||||
Light crude oil ($ per bbl) | (8.62 | ) | (1.77 | ) | (0.59 | ) | (1.05 | ) | (1.98 | ) | |||||||||||||||
Natural gas ($ millions) | 16.0 | 27.2 | 6.5 | 56.1 | 8.8 | ||||||||||||||||||||
Natural gas ($ per mcf) | 0.70 | 1.13 | 0.30 | 0.58 | 0.14 | ||||||||||||||||||||
Combined ($ millions) | (4.5 | ) | 23.1 | 5.1 | 46.0 | (7.0 | ) | ||||||||||||||||||
Combined ($ per boe) | (0.58 | ) | 2.94 | 0.72 | 1.44 | (0.30 | ) | ||||||||||||||||||
($ millions) | Three months ended | Twelve months ended | |||||||||||||||||||||||||||||||||||||||||||
Dec 31, | % of | Sept 30, | % of | Dec 31, | % of | Dec 31, | % of | Dec 31, | % of | ||||||||||||||||||||||||||||||||||||
Sales Revenue | 2007 | total | 2007 | total | 2006 | total | 2007 | total | 2006 | total | |||||||||||||||||||||||||||||||||||
Light crude oil | 175.6 | 41 | 172.0 | 41 | 138.8 | 40 | 690.8 | 40 | 532.4 | 44 | |||||||||||||||||||||||||||||||||||
Natural gas | 158.8 | 37 | 160.8 | 38 | 153.3 | 44 | 710.1 | 41 | 462.4 | 38 | |||||||||||||||||||||||||||||||||||
Natural gas liquids | 57.9 | 14 | 56.1 | 13 | 43.2 | 12 | 202.1 | 12 | 141.2 | 12 | |||||||||||||||||||||||||||||||||||
Heavy oil | 31.1 | 8 | 31.4 | 8 | 16.3 | 4 | 116.5 | 7 | 76.6 | 6 | |||||||||||||||||||||||||||||||||||
Brokered sales/sulphur | 1.8 | — | 0.4 | — | (0.7 | ) | — | 2.5 | — | 1.5 | — | ||||||||||||||||||||||||||||||||||
Total oil and gas sales | 425.2 | 420.7 | 350.9 | 1,722.0 | 1,214.1 | ||||||||||||||||||||||||||||||||||||||||
($ millions) | Light oil | Natural gas | NGL | Heavy oil | Other | Total | ||||||||||||||||||||
Year ended December 31, 2006 | 532.4 | 462.4 | 141.2 | 76.6 | 1.5 | 1,214.1 | ||||||||||||||||||||
Effect of change in product prices | 39.4 | (36.1 | ) | 6.0 | 5.9 | — | 15.2 | |||||||||||||||||||
Effect of change in sales volumes | 113.2 | 236.2 | 54.9 | 34.0 | — | 438.3 | ||||||||||||||||||||
Effect of change in realized commodity risk management activities | 5.7 | 47.3 | — | — | — | 53.0 | ||||||||||||||||||||
Other | 0.1 | 0.3 | — | — | 1.0 | 1.4 | ||||||||||||||||||||
Year ended December 31, 2007 | 690.8 | 710.1 | 202.1 | 116.5 | 2.5 | 1,722.0 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Processing & other income | 4.1 | 6.8 | 6.2 | 20.6 | 18.8 | ||||||||||||||||||||
$ per boe | 0.53 | 0.85 | 0.86 | 0.64 | 0.82 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Royalty expense | 85.4 | 68.3 | 73.1 | 319.3 | 241.5 | ||||||||||||||||||||
$ per boe | 11.01 | 8.67 | 10.23 | 10.01 | 10.53 | ||||||||||||||||||||
Royalties as a percent of sales | 20.0 | % | 16.2 | % | 20.8 | % | 18.5 | % | 19.9 | % | |||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Operating expenses | 103.8 | 89.6 | 99.7 | 406.5 | 270.5 | ||||||||||||||||||||
$ per boe | 13.38 | 11.38 | 13.97 | 12.74 | 11.80 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Net operating expenses | 99.7 | 82.8 | 93.5 | 385.9 | 251.7 | ||||||||||||||||||||
$ per boe | 12.85 | 10.53 | 13.11 | 12.10 | 10.98 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Light oil transportation | 1.2 | 1.2 | 0.5 | 3.5 | 2.0 | ||||||||||||||||||||
$ per bbl | 0.49 | 0.49 | 0.21 | 0.37 | 0.25 | ||||||||||||||||||||
Natural gas transportation | 2.1 | 2.5 | 1.8 | 9.1 | 5.6 | ||||||||||||||||||||
$ per mcf | 0.09 | 0.10 | 0.09 | 0.09 | 0.09 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Purchased and capitalized | 8.1 | 7.4 | 9.4 | 26.1 | 34.6 | ||||||||||||||||||||
Amortization | 7.5 | 8.5 | 9.3 | 34.1 | 34.6 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
Combined Netbacks ($ per boe) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Sales price | 54.58 | 53.34 | 49.24 | 53.90 | 52.88 | ||||||||||||||||||||
Other production income | 0.23 | 0.05 | (0.09 | ) | 0.08 | 0.06 | |||||||||||||||||||
54.81 | 53.39 | 49.15 | 53.98 | 52.94 | |||||||||||||||||||||
Processing and other income | 0.53 | 0.85 | 0.86 | 0.64 | 0.82 | ||||||||||||||||||||
Royalties | (11.01 | ) | (8.67 | ) | (10.23 | ) | (10.01 | ) | (10.53 | ) | |||||||||||||||
Operating expenses | (13.38 | ) | (11.38 | ) | (13.97 | ) | (12.74 | ) | (11.80 | ) | |||||||||||||||
Transportation costs | (0.42 | ) | (0.46 | ) | (0.33 | ) | (0.40 | ) | (0.33 | ) | |||||||||||||||
Amortization of injectants | (0.97 | ) | (1.07 | ) | (1.31 | ) | (1.07 | ) | (1.51 | ) | |||||||||||||||
Operating netback | 29.56 | 32.66 | 24.17 | 30.40 | 29.59 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
Light Crude Netbacks ($ per bbl) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Sales price | 73.69 | 75.10 | 60.35 | 71.88 | 66.85 | ||||||||||||||||||||
Other production income | 0.36 | 0.13 | (0.31 | ) | 0.15 | 0.13 | |||||||||||||||||||
74.05 | 75.23 | 60.04 | 72.03 | 66.98 | |||||||||||||||||||||
Processing and other income | 0.33 | 0.77 | 0.64 | 0.44 | 0.58 | ||||||||||||||||||||
Royalties | (13.86 | ) | (10.65 | ) | (11.65 | ) | (11.57 | ) | (10.63 | ) | |||||||||||||||
Operating expenses | (15.20 | ) | (16.44 | ) | (17.95 | ) | (14.85 | ) | (13.78 | ) | |||||||||||||||
Transportation costs | (0.49 | ) | (0.49 | ) | (0.21 | ) | (0.37 | ) | (0.25 | ) | |||||||||||||||
Amortization of injectants | (3.14 | ) | (3.69 | ) | (4.08 | ) | (3.54 | ) | (4.35 | ) | |||||||||||||||
Operating netback | 41.69 | 44.73 | 26.79 | 42.14 | 38.55 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
Heavy Oil Netbacks ($ per bbl) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Sales price | 45.47 | 47.30 | 37.61 | 44.53 | 42.26 | ||||||||||||||||||||
Processing and other income | 0.19 | 0.50 | 0.80 | 0.27 | 0.43 | ||||||||||||||||||||
Royalties | (5.91 | ) | (6.90 | ) | (5.44 | ) | (5.86 | ) | (4.53 | ) | |||||||||||||||
Operating expenses | (12.92 | ) | (9.43 | ) | (14.06 | ) | (12.71 | ) | (15.16 | ) | |||||||||||||||
Operating netback | 26.83 | 31.47 | 18.91 | 26.23 | 23.00 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
Natural Gas Netbacks ($ per mcf) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Sales price | 6.90 | 6.67 | 7.12 | 7.29 | 7.22 | ||||||||||||||||||||
Other production income | 0.04 | — | — | 0.01 | 0.01 | ||||||||||||||||||||
6.94 | 6.67 | 7.12 | 7.30 | 7.23 | |||||||||||||||||||||
Processing and other income | 0.14 | 0.19 | 0.20 | 0.16 | 0.21 | ||||||||||||||||||||
Royalties | (1.22 | ) | (0.92 | ) | (1.41 | ) | (1.33 | ) | (1.54 | ) | |||||||||||||||
Operating expenses | (2.02 | ) | (1.48 | ) | (1.90 | ) | (1.92 | ) | (1.65 | ) | |||||||||||||||
Transportation costs | (0.09 | ) | (0.10 | ) | (0.09 | ) | (0.09 | ) | (0.09 | ) | |||||||||||||||
Operating netback | 3.75 | 4.36 | 3.92 | 4.12 | 4.16 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
NGLs Netbacks ($ per bbl) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Sales price | 67.64 | 61.69 | 52.69 | 58.86 | 57.11 | ||||||||||||||||||||
Royalties | (23.61 | ) | (18.82 | ) | (16.61 | ) | (18.49 | ) | (20.17 | ) | |||||||||||||||
Operating expenses | (14.29 | ) | (10.96 | ) | (14.00 | ) | (12.65 | ) | (11.12 | ) | |||||||||||||||
Operating netback | 29.74 | 31.91 | 22.08 | 27.72 | 25.82 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Interest Expense | 19.7 | 19.6 | 12.8 | 84.3 | 32.1 | ||||||||||||||||||||
MANAGEMENT’S DISCUSSION & ANALYSIS
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Cash G&A expense | 12.4 | 8.3 | 11.7 | 50.5 | 34.1 | ||||||||||||||||||||
$ per boe | 1.60 | 1.05 | 1.63 | 1.58 | 1.49 | ||||||||||||||||||||
Non-cash G&A expense | 1.8 | 0.4 | (0.3 | ) | 5.4 | 2.5 | |||||||||||||||||||
$ per boe | 0.22 | 0.05 | (0.04 | ) | 0.17 | 0.11 | |||||||||||||||||||
Total G&A | 14.2 | 8.7 | 11.4 | 55.9 | 36.6 | ||||||||||||||||||||
Total G&A ($ per boe) | 1.82 | 1.10 | 1.59 | 1.75 | 1.60 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Management Fee | (2.2 | ) | 2.8 | (0.7 | ) | 6.8 | 9.9 | ||||||||||||||||||
$ per boe | (0.28 | ) | 0.36 | (0.09 | ) | 0.21 | 0.43 | ||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Depletion and depreciation | 156.0 | 157.5 | 129.2 | 639.1 | 351.6 | ||||||||||||||||||||
$ per boe | 20.11 | 19.99 | 18.09 | 20.03 | 15.33 | ||||||||||||||||||||
Accretion | 6.5 | 6.2 | 4.9 | 25.7 | 16.6 | ||||||||||||||||||||
$ per boe | 0.84 | 0.79 | 0.68 | 0.81 | 0.72 | ||||||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ millions) | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Geological and geophysical | 5.0 | 1.8 | 6.1 | 12.6 | 8.9 | ||||||||||||||||||||
Drilling and completions | 62.1 | 39.1 | 83.6 | 215.4 | 217.1 | ||||||||||||||||||||
Plant and facilities | 19.0 | 10.7 | 26.6 | 41.9 | 56.9 | ||||||||||||||||||||
Land purchases | 2.7 | 1.4 | 5.5 | 13.2 | 17.9 | ||||||||||||||||||||
Development capital | 88.8 | 53.0 | 121.8 | 283.1 | 300.8 | ||||||||||||||||||||
Other capital | 6.9 | 12.7 | 1.0 | 26.6 | 2.6 | ||||||||||||||||||||
Total capital expenditures | 95.7 | 65.7 | 122.8 | 309.7 | 303.4 | ||||||||||||||||||||
Business acquisitions | (0.6 | ) | 0.4 | 900.7 | 923.1 | 1,396.4 | |||||||||||||||||||
Property acquisitions | 9.0 | — | 0.5 | 9.0 | 50.3 | ||||||||||||||||||||
Proceeds on property dispositions | (23.7 | ) | (163.1 | ) | 0.5 | (458.8 | ) | (15.2 | ) | ||||||||||||||||
Net capital expenditures and acquisitions | 80.4 | (97.0 | ) | 1,024.5 | 783.0 | 1,734.9 | |||||||||||||||||||
($ thousands) | 2007 | 2006 | |||||||||
Term credit facilities | 513,998 | 257,000 | |||||||||
Senior unsecured notes | 689,238 | 347,200 | |||||||||
Working capital deficit excluding bank indebtedness (cash and term deposits)(1) | 191,620 | 151,575 | |||||||||
Bank indebtedness (cash and term deposits) | (2,017 | ) | 9,374 | ||||||||
Net debt excluding convertible debentures | 1,392,839 | 765,149 | |||||||||
Convertible debentures | 75,030 | 75,127 | |||||||||
Net debt including convertible debentures | 1,467,869 | 840,276 | |||||||||
Trust unitholders’ equity | 2,756,220 | 3,049,677 | |||||||||
Net debt excluding convertible debentures as a percentage of total book capitalization | 33.6 | % | 20.1 | % | |||||||
Net debt including convertible debentures as a percentage of total book capitalization | 34.8 | % | 21.6 | % | |||||||
Cash flow from operating activities | 800,344 | 554,368 | |||||||||
Net debt excluding convertible debentures to cash flow from operating activities | 1.7 | 1.4 | |||||||||
Net debt including convertible debentures to cash flow from operating activities | 1.8 | 1.5 | |||||||||
(1) | Prior year restated to conform to presentation adopted in current year |
1. | Total senior debt should not be greater than three times Earnings Before Income Taxes Depreciation and Amortization (EBITDA) for the last four fiscal quarters | |
2. | Total debt should not be greater than 3.5 times EBITDA for the last four fiscal quarters | |
3. | Total senior debt should be less than 50 percent of total book capitalization | |
4. | EBITDA should not be less than four times interest expense |
Three months ended | Twelve months ended | ||||||||||||||||||||||||
($ thousands, except per trust unit amounts | Dec 31, 2007 | Sept 30, 2007 | Dec 31, 2006 | Dec 31, 2007 | Dec 31, 2006 | ||||||||||||||||||||
Cash flows from operating activities | 196,325 | 217,630 | 91,237 | 800,344 | 554,368 | ||||||||||||||||||||
Net income (loss) | (3,665 | ) | 161,492 | 3,310 | 359,652 | 262,303 | |||||||||||||||||||
Distributions declared | 166,631 | 172,109 | 185,651 | 706,601 | 559,063 | ||||||||||||||||||||
Distributions declared per trust unit | 0.675 | 0.70 | 0.75 | 2.875 | 3.00 | ||||||||||||||||||||
Excess (shortfall) of cash flows from operating activities over distributions declared | 29,694 | 45,521 | (94,414 | ) | 93,743 | (4,695 | ) | ||||||||||||||||||
Per trust unit | 0.12 | 0.19 | (0.43 | ) | 0.38 | (0.03 | ) | ||||||||||||||||||
Shortfall of net income over distributions declared | (170,296 | ) | (10,617 | ) | (182,341 | ) | (346,949 | ) | (296,760 | ) | |||||||||||||||
Per trust unit | (0.69 | ) | (0.04 | ) | (0.83 | ) | (1.41 | ) | (1.69 | ) | |||||||||||||||
Ratio of distributions declared over cash flows from operating activities | 85 | % | 79 | % | 203 | % | 88 | % | 101 | % | |||||||||||||||
($ thousands) | 2008 | 2009 | 2010 | 2011 | 2012 | Thereafter | Total | |||||||||||||||||||||||
Long term debt(1) | — | — | 662,693 | — | — | 546,574 | 1,209,267 | |||||||||||||||||||||||
Interest payments on long term debt(2) | 40,801 | 40,801 | 33,407 | 33,407 | 33,407 | 130,760 | 312,583 | |||||||||||||||||||||||
Convertible debentures(3) | — | — | 74,700 | — | — | — | 74,700 | |||||||||||||||||||||||
Interest payments on convertible debentures(4) | 4,810 | 4,810 | 4,810 | — | — | — | 14,430 | |||||||||||||||||||||||
Other(5) | 9,015 | 9,232 | 8,652 | 8,221 | 8,139 | 42,028 | 85,287 | |||||||||||||||||||||||
54,626 | 54,843 | 784,262 | 41,628 | 41,546 | 719,362 | 1,696,267 | ||||||||||||||||||||||||
Purchase obligations | ||||||||||||||||||||||||||||||
Pipeline transportation | 43,595 | 36,254 | 19,603 | 17,528 | 15,796 | 41,339 | 174,115 | |||||||||||||||||||||||
CO2 purchases(6) | 7,357 | 3,586 | 3,616 | 3,196 | 2,890 | 9,784 | 30,429 | |||||||||||||||||||||||
50,952 | 39,840 | 23,219 | 20,724 | 18,686 | 51,123 | 204,544 | ||||||||||||||||||||||||
Remediation trust fund payments | 250 | 250 | 250 | 250 | 250 | 11,500 | 12,750 | |||||||||||||||||||||||
105,828 | 94,933 | 807,731 | 62,602 | 60,482 | 781,985 | 1,913,561 | ||||||||||||||||||||||||
(1) | The debt repayment includes the principal owing at maturity on foreign denominated fixed rate debt. (see Note 9 of the financial statements) | |
(2) | Interest payments relate to the interest payable on foreign denominated fixed rate debt using the year-end exchange rate | |
(3) | Includes repayment of convertible debentures on maturity (see Note 8 of the financial statements), and assumes no conversion of convertible debentures to trust units | |
(4) | Includes annual interest on convertible debentures outstanding at year-end and assumes no conversion of convertible debentures prior to maturity | |
(5) | Includes office rent and vehicle leases | |
(6) | For the Weyburn CO2 project, prices are denominated in U.S. dollars and have been translated at the year-end exchange rate. For the Judy Creek CO2 pilot project, prices are denominated in Canadian dollars |
High | Low | Close | Volume | Value | ||||||||||||||||||
(000’s) | ($ millions) | |||||||||||||||||||||
TSX — PGF.UN ($ Cdn) | ||||||||||||||||||||||
2007 1st quarter | 20.85 | 18.62 | 19.45 | 37,742 | 744.8 | |||||||||||||||||
2nd quarter | 21.04 | 18.82 | 20.27 | 28,348 | 561.5 | |||||||||||||||||
3rd quarter | 20.70 | 16.92 | 18.64 | 27,970 | 524.5 | |||||||||||||||||
4th quarter | 18.68 | 17.00 | 17.62 | 23,559 | 423.1 | |||||||||||||||||
Year | 21.04 | 16.92 | 17.62 | 117,619 | 2,253.9 | |||||||||||||||||
2006 1st quarter | — | — | — | — | — | |||||||||||||||||
2nd quarter | — | — | — | — | — | |||||||||||||||||
3rd quarter * | 26.11 | 21.02 | 21.94 | 29,262 | 708.0 | |||||||||||||||||
4th quarter | 22.69 | 16.81 | 19.94 | 75,576 | 1,505.0 | |||||||||||||||||
Year | 26.11 | 16.81 | 19.94 | 104,838 | 2,213.0 | |||||||||||||||||
NYSE — PGH ($ U.S.) | ||||||||||||||||||||||
2007 1st quarter | 17.96 | 15.82 | 16.87 | 26,633 | 449.1 | |||||||||||||||||
2nd quarter | 19.84 | 16.45 | 19.09 | 23,668 | 428.6 | |||||||||||||||||
3rd quarter | 19.85 | 16.25 | 18.84 | 19,284 | 346.9 | |||||||||||||||||
4th quarter | 19.21 | 17.30 | 17.77 | 13,980 | 256.4 | |||||||||||||||||
Year | 19.85 | 15.82 | 17.77 | 83,565 | 1,481.0 | |||||||||||||||||
2006 1st quarter | 25.15 | 21.50 | 23.10 | 13,421 | 316.2 | |||||||||||||||||
2nd quarter | 25.00 | 21.85 | 24.09 | 14,277 | 337.0 | |||||||||||||||||
3rd quarter | 24.95 | 18.90 | 19.62 | 27,359 | 604.0 | |||||||||||||||||
4th quarter | 20.25 | 14.78 | 17.21 | 55,108 | 955.6 | |||||||||||||||||
Year | 25.15 | 14.78 | 17.21 | 110,165 | 2,212.8 | |||||||||||||||||
TSX — PGF.A ($ Cdn) | ||||||||||||||||||||||
2007 1st quarter | — | — | — | — | — | |||||||||||||||||
2nd quarter | — | — | — | — | — | |||||||||||||||||
3rd quarter | — | — | — | — | — | |||||||||||||||||
4th quarter | — | — | — | — | — | |||||||||||||||||
Year | — | — | — | — | — | |||||||||||||||||
2006 1st quarter | 28.96 | 24.96 | 26.88 | 1,244 | 33.8 | |||||||||||||||||
2nd quarter | 28.50 | 24.20 | 26.70 | 1,810 | 47.6 | |||||||||||||||||
3rd quarter * | 28.25 | 24.95 | 25.30 | 4,297 | 110.6 | |||||||||||||||||
4th quarter | — | — | — | — | — | |||||||||||||||||
Year | 28.96 | 24.20 | 25.30 | 7,351 | 192.0 | |||||||||||||||||
TSX — PGF.B ($ Cdn) | ||||||||||||||||||||||
2007 1st quarter | — | — | — | — | — | |||||||||||||||||
2nd quarter | — | — | — | — | — | |||||||||||||||||
3rd quarter | — | — | — | — | — | |||||||||||||||||
4th quarter | — | — | — | — | — | |||||||||||||||||
Year | — | — | — | — | — | |||||||||||||||||
2006 1st quarter | 24.50 | 20.71 | 23.32 | 18,338 | 420.1 | |||||||||||||||||
2nd quarter | 26.05 | 22.41 | 26.05 | 18,982 | 459.6 | |||||||||||||||||
3rd quarter * | 27.25 | 24.84 | 25.31 | 14,226 | 364.0 | |||||||||||||||||
4th quarter | — | — | — | — | — | |||||||||||||||||
Year | 27.25 | 20.71 | 25.31 | 51,546 | 1,243.7 | |||||||||||||||||
* | On July 27, 2006, Pengrowth’s Class A trust units and Class B trust units were consolidated into a single class of trust units pursuant to which the Class A trust units were delisted from the Toronto Stock Exchange, Class A trust units were converted into Class B trust units (with the exception of Class A trust units held by residents of Canada who elected to retain their Class A trust units) and the Class B trust units were renamed as trust units and their trading symbol changed to PGF.UN |
2007 | Q1 | Q2 | Q3 | Q4 | ||||||||||||||
Oil and gas sales ($000’s) | 432,108 | 443,977 | 420,704 | 425,249 | ||||||||||||||
Net income/(loss) ($000’s) | (69,834 | ) | 271,659 | 161,492 | (3,665 | ) | ||||||||||||
Net income/(loss) per trust unit ($) | (0.29 | ) | 1.11 | 0.66 | (0.01 | ) | ||||||||||||
Net income/(loss) per trust unit — diluted ($) | (0.29 | ) | 1.10 | 0.66 | (0.01 | ) | ||||||||||||
Cash flow from operating activities ($000’s) | 136,429 | 249,960 | 217,630 | 196,325 | ||||||||||||||
Distributions declared ($000’s) | 183,534 | 184,327 | 172,109 | 166,631 | ||||||||||||||
Distributions declared per trust unit ($) | 0.75 | 0.75 | 0.70 | 0.675 | ||||||||||||||
Daily production (boe) | 90,068 | 89,633 | 85,654 | 84,331 | ||||||||||||||
Total production (mboe) | 8,106 | 8,157 | 7,880 | 7,758 | ||||||||||||||
Average realized price ($ per boe) | 53.30 | 54.39 | 53.34 | 54.58 | ||||||||||||||
Operating netback ($ per boe) | 29.87 | 29.56 | 32.66 | 29.56 | ||||||||||||||
2006 | Q1 | Q2 | Q3 | Q4 | ||||||||||||||
Oil and gas sales ($000’s) | 291,896 | 283,532 | 287,757 | 350,908 | ||||||||||||||
Net income ($000’s) | 66,335 | 110,116 | 82,542 | 3,310 | ||||||||||||||
Net income per trust unit ($) | 0.41 | 0.69 | 0.51 | 0.01 | ||||||||||||||
Net income per trust unit — diluted ($) | 0.41 | 0.68 | 0.51 | 0.01 | ||||||||||||||
Cash flow from operating activities ($000’s) | 156,360 | 126,800 | 179,971 | 91,237 | ||||||||||||||
Distributions declared ($000’s) | 120,302 | 120,597 | 132,513 | 185,651 | ||||||||||||||
Distributions declared per trust unit ($) | 0.75 | 0.75 | 0.75 | 0.75 | ||||||||||||||
Daily production (boe) | 58,845 | 56,325 | 58,344 | 77,614 | ||||||||||||||
Total production (mboe) | 5,296 | 5,126 | 5,368 | 7,141 | ||||||||||||||
Average realized price ($ per boe) | 55.04 | 54.91 | 53.67 | 49.24 | ||||||||||||||
Operating netback ($ per boe) | 31.44 | 33.94 | 30.82 | 24.17 | ||||||||||||||
Twelve months ended December 31 | |||||||||||||||
($ thousands) | 2007 | 2006 | 2005 | ||||||||||||
Oil and gas sales | 1,722,038 | 1,214,093 | 1,151,510 | ||||||||||||
Net income | 359,652 | 262,303 | 326,326 | ||||||||||||
Net income per trust unit ($) | 1.47 | 1.49 | 2.08 | ||||||||||||
Net income per trust unit — diluted ($) | 1.46 | 1.49 | 2.07 | ||||||||||||
Distributions declared per trust unit ($) | 2.875 | 3.00 | 2.82 | ||||||||||||
Total assets(1) | 5,234,251 | 4,690,129 | 2,391,432 | ||||||||||||
Long term debt(2) | 1,278,266 | 679,327 | 368,089 | ||||||||||||
Trust unitholders’ equity | 2,756,220 | 3,049,677 | 1,475,996 | ||||||||||||
Number of trust units outstanding at year-end (thousands) | 246,846 | 244,017 | 159,864 | ||||||||||||
(1) | Prior years restated to conform to presentation adopted in the current year | |
(2) | Includes long term debt and convertible debentures |
• | 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 including implementation of the October 31 Proposals governing such royalties, taxes and fees could have a material impact on Pengrowth’s financial results and the value of Pengrowth trust units; |
• | Changes to the royalty regime in Alberta were announced on October 25, 2007. The full details required to accurately assess the impact are not known at this time but will reduce future cash flows and reserve valuations; | |
• | Oil and gas operations carry the risk of damaging the local environment in the event of equipment or operational failure. The cost to remediate any environmental damage could be significant; | |
• | 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 future regulations to reduce greenhouse gas and other emissions; | |
• | Pengrowth’s oil and gas reserves will be depleted over time and our level of cash flow from operations 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. Additional uncertainty with new legislation may limit access to capital or increase the cost of raising capital; | |
• | Increased competition for properties will drive the cost of acquisitions 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 has increased the cost of goods and services and makes it more difficult to hire and retain professional staff; | |
• | Changing interest rates influence borrowing costs and the availability of capital; | |
• | Failing a financial covenant may result in one or more of Pengrowth’s loans being in default. In certain circumstances, being in default of one loan may result in other loans to also be in default; | |
• | Investors’ interest in the oil and gas sector may change over time which would affect the availability of capital and the value of Pengrowth trust units; | |
• | Inflation may result in escalating costs which could impact unitholder distributions and the value of Pengrowth trust units; | |
• | Continued uncertainty in the credit markets may restrict the availability or increase the cost of borrowing required for future development and acquisitions; | |
• | Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs; and | |
• | 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. |
James S. Kinnear | Christopher G. Webster | |
Chairman, President and | Chief Financial Officer | |
Chief Executive Officer |
Chartered Accountants | ||||
Calgary, Canada | ||||
March 3, 2008 |
Chartered Accountants | ||||
Calgary, Canada | ||||
March 3, 2008 |
(stated in thousands of dollars)
As at December 31 | 2007 | 2006 | |||||||||
ASSETS | |||||||||||
Current assets | |||||||||||
Cash and term deposits | $ | 2,017 | $ | — | |||||||
Accounts receivable | 206,583 | 171,876 | |||||||||
Due from Pengrowth Management Limited | 731 | — | |||||||||
Fair value of risk management contracts (Note 19) | 8,034 | 37,972 | |||||||||
Future income taxes (Note 11) | 18,751 | — | |||||||||
236,116 | 209,848 | ||||||||||
Fair value of risk management contracts(Note 19) | 6,024 | 495 | |||||||||
Deposit on acquisition | — | 103,750 | |||||||||
Other assets(Note 5) | 24,831 | 36,132 | |||||||||
Property, plant and equipment(Note 6) | 4,306,682 | 3,741,602 | |||||||||
Goodwill(Note 4) | 660,598 | 598,302 | |||||||||
TOTAL ASSETS | $ | 5,234,251 | $ | 4,690,129 | |||||||
LIABILITIES AND UNITHOLDERS’ EQUITY | |||||||||||
Current liabilities | |||||||||||
Bank indebtedness | $ | — | $ | 9,374 | |||||||
Accounts payable and accrued liabilities | 239,091 | 221,213 | |||||||||
Distributions payable to unitholders | 111,119 | 122,080 | |||||||||
Due to Pengrowth Management Limited | — | 2,101 | |||||||||
Fair value of risk management contracts (Note 19) | 70,846 | — | |||||||||
Future income taxes (Note 11) | — | 11,012 | |||||||||
Contract liabilities (Note 7) | 4,663 | 5,017 | |||||||||
425,719 | 370,797 | ||||||||||
Fair value of risk management contracts(Note 19) | 22,613 | 1,367 | |||||||||
Contract liabilities(Note 7) | 12,162 | 16,825 | |||||||||
Convertible debentures(Note 8) | 75,030 | 75,127 | |||||||||
Long term debt(Note 9) | 1,203,236 | 604,200 | |||||||||
Asset retirement obligations(Note 10) | 352,171 | 255,331 | |||||||||
Future income taxes(Note 11) | 387,100 | 316,805 | |||||||||
Trust unitholders’ equity(Note 12) | |||||||||||
Trust Unitholders’ capital | 4,432,737 | 4,383,993 | |||||||||
Equity portion of convertible debentures | 160 | 160 | |||||||||
Contributed surplus | 9,679 | 4,931 | |||||||||
Deficit (Note 14) | (1,686,356 | ) | (1,339,407 | ) | |||||||
2,756,220 | 3,049,677 | ||||||||||
Commitments(Note 20) | |||||||||||
Contingencies(Note 21) | |||||||||||
Subsequent Events(Note 22) | |||||||||||
TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY | $ | 5,234,251 | $ | 4,690,129 | |||||||
Director | Director |
(stated in thousands of dollars)
Years ended December 31 | 2007 | 2006 | |||||||||
REVENUES | |||||||||||
Oil and gas sales | $ | 1,722,038 | $ | 1,214,093 | |||||||
Unrealized (loss) gain on commodity risk management (Note 19) | (122,307 | ) | 26,499 | ||||||||
Processing and other income | 20,573 | 18,768 | |||||||||
Royalties, net of incentives | (319,319 | ) | (241,494 | ) | |||||||
Net revenue | 1,300,985 | 1,017,866 | |||||||||
EXPENSES | |||||||||||
Operating | 406,522 | 270,519 | |||||||||
Transportation | 12,672 | 7,621 | |||||||||
Amortization of injectants for miscible floods | 34,063 | 34,644 | |||||||||
Interest on bank indebtedness | 13,876 | — | |||||||||
Interest on long term debt | 70,416 | 32,109 | |||||||||
General and administrative | 55,903 | 36,613 | |||||||||
Management fee | 6,807 | 9,941 | |||||||||
Foreign exchange (gain) loss (Note 15) | (61,857 | ) | 22 | ||||||||
Depletion, depreciation and amortization | 639,084 | 351,575 | |||||||||
Accretion (Note 10) | 25,722 | 16,591 | |||||||||
Other expenses | 2,737 | 10,197 | |||||||||
1,205,945 | 769,832 | ||||||||||
Income before taxes | 95,040 | 248,034 | |||||||||
Future income tax reduction (Note 11) | (264,612 | ) | (14,269 | ) | |||||||
NET INCOME | $ | 359,652 | $ | 262,303 | |||||||
Deficit, beginning of year | (1,339,407 | ) | (1,042,647 | ) | |||||||
Distributions declared | (706,601 | ) | (559,063 | ) | |||||||
DEFICIT, END OF YEAR | $ | (1,686,356 | ) | $ | (1,339,407 | ) | |||||
Net income per trust unit (Note 18) | |||||||||||
Basic | $ | 1.47 | $ | 1.49 | |||||||
Diluted | $ | 1.46 | $ | 1.49 | |||||||
(stated in thousands of dollars)
Years ended December 31 | 2007 | 2006 | |||||||||
CASH PROVIDED BY (USED FOR): | |||||||||||
OPERATING | |||||||||||
Net income | $ | 359,652 | $ | 262,303 | |||||||
Depletion, depreciation and accretion | 664,806 | 368,166 | |||||||||
Future income tax reduction (Note 11) | (264,612 | ) | (14,269 | ) | |||||||
Contract liability amortization (Note 7) | (5,017 | ) | (5,447 | ) | |||||||
Amortization of injectants | 34,063 | 34,644 | |||||||||
Purchase of injectants | (26,052 | ) | (34,630 | ) | |||||||
Expenditures on remediation | (11,428 | ) | (9,093 | ) | |||||||
Unrealized foreign exchange (gain) loss (Note 15) | (73,940 | ) | 480 | ||||||||
Unrealized loss (gain) on risk management contracts (Note 19) | 130,374 | (26,499 | ) | ||||||||
Trust unit based compensation (Note 13) | 5,351 | 2,546 | |||||||||
Deferred charges and other items | 2,987 | 498 | |||||||||
Changes in non-cash operating working capital (Note 16) | (15,840 | ) | (24,331 | ) | |||||||
800,344 | 554,368 | ||||||||||
FINANCING | |||||||||||
Distributions paid (Note 14) | (717,562 | ) | (516,966 | ) | |||||||
Bank indebtedness | (9,374 | ) | 9,374 | ||||||||
Change in long term debt, net | 674,276 | (54,870 | ) | ||||||||
Redemption of convertible debentures (Note 8) | — | (21,184 | ) | ||||||||
Repayment of note payable | — | (20,000 | ) | ||||||||
Proceeds from issue of trust units | 48,141 | 971,791 | |||||||||
(4,519 | ) | 368,145 | |||||||||
INVESTING | |||||||||||
Business acquisition (Note 4) | (923,121 | ) | (500,451 | ) | |||||||
Expenditures on property, plant and equipment | (309,708 | ) | (300,809 | ) | |||||||
Other property acquisitions | (9,012 | ) | (52,880 | ) | |||||||
Proceeds on property dispositions | 458,804 | 15,230 | |||||||||
Deposit on acquisition | — | (103,750 | ) | ||||||||
Change in remediation trust funds | (6,950 | ) | (2,815 | ) | |||||||
Change in non-cash investing working capital (Note 16) | (3,821 | ) | 37,529 | ||||||||
(793,808 | ) | (907,946 | ) | ||||||||
CHANGE IN CASH AND TERM DEPOSITS | 2,017 | 14,567 | |||||||||
CASH AND TERM DEPOSITS (BANK INDEBTEDNESS) AT BEGINNING OF YEAR | — | (14,567 | ) | ||||||||
CASH AND TERM DEPOSITS AT END OF YEAR | $ | 2,017 | $ | — | |||||||
92 | Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT |
I. | Pengrowth had deferred $2.8 million of debt issue costs related to prior issuances of private placement debt. The deferred issue costs were being amortized on a straight-line basis over the term of the debt. On January 1, 2007, an adjustment of $1.6 million was made to reduce the carrying amount of the related debt and other assets. No adjustment was made to opening retained earnings for the cumulative effect of the change in accounting policy as the amount was not significant. | |
II. | Foreign exchange swaps were used to fix the foreign exchange rate on the interest and principal of the Pounds Sterling 50 million ten year senior unsecured notes (see Note 9). In prior years, Pengrowth had formally documented this relationship as a hedge and applied hedge accounting to this transaction which resulted in any unrealized foreign exchange gains (losses) on the translation of the debt to be deferred and recorded in other assets (other liabilities). On January 1, 2007, Pengrowth ceased to designate the foreign exchange swaps as a cash flow hedge of the U.K. Pounds Sterling 50 million unsecured notes and as a result hedge accounting was no longer used to account for the transaction. As the hedging relationship qualified for hedge accounting under the revised hedging standards, $13.6 million of deferred foreign exchange loss related to the debt was reclassified to accumulated other comprehensive income. An asset related to the fair value of foreign exchange swaps of $13.9 million was recognized on the balance sheet on January 1, 2007 with a corresponding adjustment to reduce accumulated other comprehensive income. The remaining balance in accumulated other comprehensive income of $0.3 million was reclassified to net income in the period as the amount was not significant. |
94 | Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT |
Allocation of Purchase Price: | ||||||
Property, plant and equipment | $ | 1,360,491 | ||||
Goodwill | 62,296 | |||||
Asset retirement obligations | (90,772 | ) | ||||
Future income taxes | (305,144 | ) | ||||
$ | 1,026,871 | |||||
Consideration: | ||||||
Cash | $ | 1,024,585 | ||||
Acquisition costs | 2,286 | |||||
$ | 1,026,871 | |||||
Carson Creek | Esprit | ||||||||||||||
Properties | Energy Trust | Total | |||||||||||||
Allocation of Purchase Price: | |||||||||||||||
Property, plant and equipment | $ | 495,806 | $ | 1,207,121 | $ | 1,702,927 | |||||||||
Goodwill | 129,745 | 285,722 | 415,467 | ||||||||||||
Fair value of commodity contracts | — | 10,601 | 10,601 | ||||||||||||
Bank debt | — | (276,870 | ) | (276,870 | ) | ||||||||||
Convertible debentures | — | (96,500 | ) | (96,500 | ) | ||||||||||
Contract liabilities | (9,073 | ) | — | (9,073 | ) | ||||||||||
Asset retirement obligations | (20,668 | ) | (51,651 | ) | (72,319 | ) | |||||||||
Future income taxes | (121,384 | ) | (110,590 | ) | (231,974 | ) | |||||||||
Working capital deficiency | — | (45,864 | ) | (45,864 | ) | ||||||||||
$ | 474,426 | $ | 921,969 | $ | 1,396,395 | ||||||||||
Consideration: | |||||||||||||||
Cash | $ | 474,089 | $ | 19,990 | $ | 494,079 | |||||||||
Pengrowth trust units issued | — | 895,944 | 895,944 | ||||||||||||
Acquisition costs | 337 | 6,035 | 6,372 | ||||||||||||
$ | 474,426 | $ | 921,969 | $ | 1,396,395 | ||||||||||
2007 | 2006 | ||||||||||
Deferred compensation expense (net of accumulated amortization of $5,077, 2006 — $2,381) | $ | — | $ | 2,696 | |||||||
Debt issue costs (net of accumulated amortization of, 2006 — $1,192) | — | 1,626 | |||||||||
— | 4,322 | ||||||||||
Deferred foreign exchange loss on translation of U.K. debt | — | 13,631 | |||||||||
Remediation trust funds (Note 10) | 18,094 | 11,144 | |||||||||
Equity investment | 6,737 | 7,035 | |||||||||
$ | 24,831 | $ | 36,132 | ||||||||
2007 | 2006 | ||||||||||
Property, plant and equipment, at cost | $ | 6,577,484 | $ | 5,365,309 | |||||||
Accumulated depletion, depreciation and amortization | (2,298,083 | ) | (1,658,999 | ) | |||||||
Net book value of property, plant and equipment | $ | 4,279,401 | 3,706,310 | ||||||||
Net book value of deferred injectant costs | 27,281 | 35,292 | |||||||||
Net book value of property, plant and equipment and deferred injectants | $ | 4,306,682 | $ | 3,741,602 | |||||||
Foreign | Edmonton Light | |||||||||||||||||
WTI Oil | Exchange Rate | Crude Oil | AECO Gas | |||||||||||||||
Year | (U.S.$/bbl) | (U.S.$/Cdn$) | (Cdn$/bbl) | (Cdn$/mmbtu) | ||||||||||||||
2008 | $ | 92.00 | 1.000 | $ | 91.10 | $ | 6.75 | |||||||||||
2009 | $ | 88.00 | 1.000 | $ | 87.10 | $ | 7.55 | |||||||||||
2010 | $ | 84.00 | 1.000 | $ | 83.10 | $ | 7.60 | |||||||||||
2011 | $ | 82.00 | 1.000 | $ | 81.10 | $ | 7.60 | |||||||||||
2012 | $ | 82.00 | 1.000 | $ | 81.10 | $ | 7.60 | |||||||||||
2013 | $ | 82.00 | 1.000 | $ | 81.10 | $ | 7.60 | |||||||||||
2014 | $ | 82.00 | 1.000 | $ | 81.10 | $ | 7.80 | |||||||||||
2015 | $ | 82.00 | 1.000 | $ | 81.10 | $ | 7.97 | |||||||||||
2016 | $ | 82.02 | 1.000 | $ | 81.12 | $ | 8.14 | |||||||||||
2017 | $ | 83.66 | 1.000 | $ | 82.76 | $ | 8.31 | |||||||||||
Thereafter | + 2.0 percent/yr | 1.000 | + 2.0 percent/yr | + 2.0 percent/yr | ||||||||||||||
2007 | 2006 | ||||||||||
Fixed price commodity contract | $ | 4,110 | $ | 7,800 | |||||||
Firm transportation contracts | 12,715 | 14,042 | |||||||||
16,825 | 21,842 | ||||||||||
Less current portion | (4,663 | ) | (5,017 | ) | |||||||
$ | 12,162 | $ | 16,825 | ||||||||
Debt | Equity | Total | ||||||||||||
Fair value on October 2, 2006 (Note 4) | $ | 96,295 | $ | 205 | $ | 96,500 | ||||||||
Amortization of debt premium | (29 | ) | — | (29 | ) | |||||||||
Redeemed for cash | (21,139 | ) | (45 | ) | (21,184 | ) | ||||||||
Balance, December 31, 2006 | $ | 75,127 | $ | 160 | $ | 75,287 | ||||||||
Amortization of debt premium | (97 | ) | — | (97 | ) | |||||||||
Balance, December 31, 2007 | $ | 75,030 | $ | 160 | $ | 75,190 | ||||||||
2007 | 2006 | ||||||||||
U.S. dollar denominated debt: | |||||||||||
U.S. dollar 150 million senior unsecured notes at 4.93 percent due April 2010 | $ | 148,053 | $ | 174,810 | |||||||
U.S. dollar 50 million senior unsecured notes at 5.47 percent due April 2013 | 49,351 | 58,270 | |||||||||
U.S. dollar 400 million senior unsecured notes at 6.35 percent due July 2017 | 394,390 | — | |||||||||
591,794 | 233,080 | ||||||||||
Pound sterling denominated 50 million unsecured notes at 5.46 percent due December 2015 | 97,444 | 114,120 | |||||||||
Canadian dollar revolving credit borrowings | 513,998 | 257,000 | |||||||||
$ | 1,203,236 | $ | 604,200 | ||||||||
2007 | 2006 | ||||||||||
Asset retirement obligations, beginning of year | $ | 255,331 | $ | 184,699 | |||||||
Increase (decrease) in liabilities during the year related to: | |||||||||||
Acquisitions | 91,333 | 72,680 | |||||||||
Disposals | (35,199 | ) | (1,500 | ) | |||||||
Additions | 3,753 | 1,649 | |||||||||
Revisions | 22,659 | (9,695 | ) | ||||||||
Accretion expense | 25,722 | 16,591 | |||||||||
Liabilities settled during the year | (11,428 | ) | (9,093 | ) | |||||||
Asset retirement obligations, end of year | $ | 352,171 | $ | 255,331 | |||||||
�� | |||||||||||
Remediation Trust Funds | 2007 | 2006 | |||||||||
Opening balance | $ | 11,144 | $ | 8,329 | |||||||
Contributions to Judy Creek Remediation Trust Fund | 917 | 1,036 | |||||||||
Contributions to SOEP Environmental Restoration Fund | 6,441 | 2,153 | |||||||||
Remediation funded by Judy Creek Remediation Trust Fund | (408 | ) | (374 | ) | |||||||
Change in remediation trust funds | 6,950 | 2,815 | |||||||||
Closing balance | $ | 18,094 | $ | 11,144 | |||||||
Expenditures on ARO | 2007 | 2006 | |||||||||
Expenditures on ARO not covered by the trust funds | $ | 11,020 | $ | 8,719 | |||||||
Expenditures on ARO covered by the trust funds | 408 | 374 | |||||||||
$ | 11,428 | $ | 9,093 | ||||||||
2007 | 2006 | ||||||||||
Income before taxes | $ | 95,040 | $ | 248,048 | |||||||
Combined federal and provincial tax rate | 32.1 | % | 34.1 | % | |||||||
Expected income tax | 30,508 | 84,584 | |||||||||
Net income of the Trust | (123,227 | ) | (85,989 | ) | |||||||
Impact of SIFT legislation | (71,048 | ) | — | ||||||||
Resource allowance | — | (8,618 | ) | ||||||||
Non-deductible crown charges | — | 17,586 | |||||||||
Unrealized foreign exchange gain | (9,254 | ) | 1 | ||||||||
Book to tax differential on dispositions | (68,722 | ) | — | ||||||||
Attributed Canadian royalty income | — | (6,616 | ) | ||||||||
Change in enacted tax rates | (59,230 | ) | (19,886 | ) | |||||||
Future tax rate difference | 19,679 | 2,491 | |||||||||
Other including stock based compensation | 16,682 | 2,178 | |||||||||
Future income tax reduction | (264,612 | ) | (14,269 | ) | |||||||
Capital taxes | — | 14 | |||||||||
$ | (264,612 | ) | $ | (14,255 | ) | ||||||
2007 | 2006 | ||||||||||
Future income tax liabilities: | |||||||||||
Property, plant, equipment and other assets | $ | 344,701 | $ | 339,660 | |||||||
Unrealized foreign exchange gain | 10,776 | 8,288 | |||||||||
Deferred partnership income | 27,929 | — | |||||||||
Other | — | 150 | |||||||||
383,406 | 348,098 | ||||||||||
Future income tax assets: | |||||||||||
Attributed Canadian royalty income | (10,351 | ) | (13,947 | ) | |||||||
Contract liabilities | (4,706 | ) | (6,334 | ) | |||||||
$ | 368,349 | $ | 327,817 | ||||||||
Years ended December 31 | 2007 | 2006 | |||||||||||||||||
Number | Number | ||||||||||||||||||
Trust units issued | of trust units | Amount | of trust units | Amount | |||||||||||||||
Balance, beginning of year | 244,016,623 | $ | 4,383,993 | 159,864,083 | $ | 2,514,997 | |||||||||||||
Issued for the Esprit Trust business combination (non-cash) | — | — | 34,725,157 | 895,944 | |||||||||||||||
Issued for cash | — | — | 47,575,000 | 987,841 | |||||||||||||||
Issue costs | — | (745 | ) | — | (51,575 | ) | |||||||||||||
Issued on redemption of DEUs (non-cash) | 2,931 | 55 | 14,523 | 233 | |||||||||||||||
Issued for cash on exercise of trust unit options and rights | 350,615 | 4,006 | 607,766 | 9,476 | |||||||||||||||
Issued for cash under Distribution Reinvestment Plan (DRIP) | 2,461,299 | 44,880 | 1,226,806 | 26,049 | |||||||||||||||
Issued on redemption of Royalty Units (non-cash) | 14,952 | — | 3,288 | — | |||||||||||||||
Trust unit rights incentive plan (non-cash exercised) | — | 548 | — | 1,028 | |||||||||||||||
Balance, end of year | 246,846,420 | $ | 4,432,737 | 244,016,623 | $ | 4,383,993 | |||||||||||||
Years ended December 31 | 2007 | 2006 | |||||||||||||||||
Number | Number | ||||||||||||||||||
Trust units issued | of trust units | Amount | of trust units | Amount | |||||||||||||||
Balance, beginning of year | 244,005,105 | $ | 4,383,819 | — | $ | — | |||||||||||||
Issued in trust unit consolidation | — | — | 160,921,001 | 2,535,949 | |||||||||||||||
Issued on conversion of Class A trust units | 9,630 | 173 | 3,450 | 57 | |||||||||||||||
Issued for the Esprit Trust business combination (non-cash) | — | — | 34,725,157 | 895,944 | |||||||||||||||
Issued for cash | — | — | 47,575,000 | 987,841 | |||||||||||||||
Issue costs | — | (745 | ) | — | (51,575 | ) | |||||||||||||
Issued on redemption of DEUs (non-cash) | 2,931 | 55 | 14,523 | 233 | |||||||||||||||
Issued for cash on exercise of trust unit options and rights | 350,615 | 4,006 | 99,228 | 1,579 | |||||||||||||||
Issued for cash under DRIP | 2,461,299 | 44,880 | 663,458 | 13,415 | |||||||||||||||
Issued on redemption of Royalty Units (non-cash) | 14,952 | — | 3,288 | — | |||||||||||||||
Trust unit rights incentive plan (non-cash exercised) | — | 548 | — | 376 | |||||||||||||||
Balance, end of year | 246,844,532 | $ | 4,432,736 | 244,005,105 | $ | 4,383,819 | |||||||||||||
Years ended December 31 | 2007 | 2006 | |||||||||||||||||
Number | Number | ||||||||||||||||||
Trust units issued | of trust units | Amount | of trust units | Amount | |||||||||||||||
Balance, beginning of year | 11,518 | $ | 174 | 77,524,673 | $ | 1,196,121 | |||||||||||||
Trust units converted to Class A trust units | (9,630 | ) | (173 | ) | 2,760 | 43 | |||||||||||||
Trust units converted to “consolidated” trust units | — | — | (77,515,915 | ) | (1,195,990 | ) | |||||||||||||
Balance, end of year | 1,888 | $ | 1 | 11,518 | $ | 174 | |||||||||||||
Year ended December 31 | 2006 | |||||||||
Number | ||||||||||
Trust units issued | of trust units | Amount | ||||||||
Balance, beginning of year | 82,301,443 | $ | 1,318,294 | |||||||
Trust units converted to (from) Class B trust units | 1,095 | 17 | ||||||||
Issued for cash on exercise of trust unit options and rights | 508,538 | 7,897 | ||||||||
Issued for cash under DRIP | 563,348 | 12,634 | ||||||||
Trust unit rights incentive plan (non-cash exercised) | — | 652 | ||||||||
Trust units renamed to become “consolidated” trust units | (83,374,424 | ) | (1,339,494 | ) | ||||||
Balance, end of year | — | $ | — | |||||||
Year ended December 31 | 2006 | |||||||||
Number | ||||||||||
Trust units issued | of trust units | Amount | ||||||||
Balance, beginning of year | 37,967 | $ | 582 | |||||||
Converted to Class A or Class B trust units | (3,855 | ) | (60 | ) | ||||||
Trust units converted to “consolidated” trust units | (34,112 | ) | (522 | ) | ||||||
Balance, end of year | — | $ | — | |||||||
2007 | 2006 | ||||||||||
Balance, beginning of year | $ | 4,931 | $ | 3,646 | |||||||
Trust unit rights incentive plan (non-cash expensed) | 1,903 | 1,298 | |||||||||
Deferred entitlement trust units (non-cash expensed) | 3,448 | 1,248 | |||||||||
Trust unit rights incentive plan (non-cash exercised) | (548 | ) | (1,028 | ) | |||||||
Deferred entitlement trust units (non-cash exercised) | (55 | ) | (233 | ) | |||||||
Balance, end of year | $ | 9,679 | $ | 4,931 | |||||||
2007 | 2006 | ||||||||||||||||||
Weighted | Weighted | ||||||||||||||||||
Number | average | Number of | average | ||||||||||||||||
DEUs | of DEUs | fair value | DEUs | fair value | |||||||||||||||
Outstanding, beginning of year | 399,568 | $ | 20.55 | 185,591 | $ | 18.32 | |||||||||||||
Granted | 451,615 | $ | 19.73 | 222,088 | $ | 22.28 | |||||||||||||
Forfeited | (92,672 | ) | $ | 20.15 | (33,981 | ) | $ | 20.13 | |||||||||||
Exercised | (2,931 | ) | $ | 20.06 | (14,207 | ) | $ | 20.43 | |||||||||||
Deemed DRIP | 112,462 | $ | 20.27 | 40,077 | $ | 19.14 | |||||||||||||
Outstanding, end of year | 868,042 | $ | 20.13 | 399,568 | $ | 20.55 | |||||||||||||
2007 | 2006 | ||||||||||||||||||
Weighted | Weighted | ||||||||||||||||||
Number | average | Number | average | ||||||||||||||||
Trust Unit Rights | of rights | exercise price | of rights | exercise price | |||||||||||||||
Outstanding at beginning of year | 1,534,241 | $ | 16.06 | 1,441,737 | $ | 14.85 | |||||||||||||
Granted(1) | 1,259,562 | $ | 19.75 | 617,409 | $ | 22.39 | |||||||||||||
Exercised | (343,925 | ) | $ | 11.35 | (452,468 | ) | $ | 14.75 | |||||||||||
Forfeited | (199,822 | ) | $ | 14.63 | (72,437 | ) | $ | 17.47 | |||||||||||
Outstanding at year-end | �� | 2,250,056 | $ | 17.39 | 1,534,241 | $ | 16.06 | ||||||||||||
Exercisable at year-end | 1,317,296 | $ | 16.30 | 969,402 | $ | 14.22 | |||||||||||||
(1) | Weighted average exercise price of rights granted are based on the exercise price at the date of grant. |
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 | ||||||||||||||||||
$9.00 to $11.99 | 255,178 | 1.1 | $ | 11.07 | 255,178 | $ | 11.07 | ||||||||||||||||
$12.00 to $14.99 | 281,990 | 2.0 | $ | 13.91 | 281,990 | $ | 13.91 | ||||||||||||||||
$15.00 to $16.99 | 97,376 | 2.8 | $ | 15.83 | 97,376 | $ | 15.83 | ||||||||||||||||
$17.00 to $18.99 | 1,206,999 | 4.2 | $ | 17.84 | 415,257 | $ | 18.55 | ||||||||||||||||
$19.00 to $23.99 | 408,513 | 3.2 | $ | 20.47 | 267,495 | $ | 20.47 | ||||||||||||||||
$9.00 to $23.99 | 2,250,056 | 3.3 | $ | 17.39 | 1,317,296 | $ | 16.30 | ||||||||||||||||
2007 | 2006 | ||||||||||||||||||
Weighted | Weighted | ||||||||||||||||||
Number | average | Number | average | ||||||||||||||||
Trust Unit Options | of options | exercise price | of options | exercise price | |||||||||||||||
Outstanding at beginning of year | 98,619 | $ | 16.12 | 259,317 | $ | 17.28 | |||||||||||||
Exercised | (6,690 | ) | $ | 15.25 | (155,298 | ) | $ | 18.03 | |||||||||||
Expired | (25,611 | ) | $ | 18.61 | (5,400 | ) | $ | 16.96 | |||||||||||
Outstanding and exercisable at year-end | 66,318 | $ | 15.25 | 98,619 | $ | 16.12 | |||||||||||||
2007 | 2006 | ||||||||||
Accumulated earnings | $ | 1,675,338 | $ | 1,315,686 | |||||||
Accumulated distributions declared | (3,361,694 | ) | (2,655,093 | ) | |||||||
$ | (1,686,356 | ) | $ | (1,339,407 | ) | ||||||
2007 | 2006 | ||||||||||
Unrealized foreign exchange loss (gain) on translation of U.S. dollar denominated debt | $ | (57,820 | ) | $ | 480 | ||||||
Unrealized foreign exchange gain on translation of U.K. Pound denominated debt | (16,120 | ) | — | ||||||||
$ | (73,940 | ) | $ | 480 | |||||||
Unrealized loss on foreign exchange risk management contracts (Note 19) | 8,067 | — | |||||||||
Realized foreign exchange (gain) loss | 4,016 | (458 | ) | ||||||||
$ | (61,857 | ) | $ | 22 | |||||||
Cash provided by (used for): | 2007 | 2006 | |||||||||
Accounts receivable | $ | (34,707 | ) | $ | 12,819 | ||||||
Accounts payable and accrued liabilities | 21,699 | (30,974 | ) | ||||||||
Due to Pengrowth Management Limited | (2,832 | ) | (6,176 | ) | |||||||
$ | (15,840 | ) | $ | (24,331 | ) | ||||||
Cash provided by (used for): | 2007 | 2006 | |||||||||
Accounts payable for capital accruals | $ | (3,821 | ) | $ | 37,529 | ||||||
2007 | 2006 | ||||||||||
Interest on long term debt | $ | 58,192 | $ | 32,183 | |||||||
Interest on bank indebtedness | 13,876 | — | |||||||||
$ | 72,068 | $ | 32,183 | ||||||||
2007 | 2006 | ||||||||||
Weighted average number of trust units — Basic | 245,470 | 175,871 | |||||||||
Dilutive effect of trust unit options, trust unit rights and DEUs | 740 | 583 | |||||||||
Weighted average number of trust units — Diluted | 246,210 | 176,454 | |||||||||
Volume | Reference | Price | ||||||||||||
Remaining Term | (bbl/d) | Point | per bbl | |||||||||||
Financial: | ||||||||||||||
Jan 1, 2008 — Oct 31, 2008 | 1,000 | WTI(1) | $74.25 Cdn | |||||||||||
Jan 1, 2008 — Dec 31, 2008 | 16,500 | WTI(1) | $76.20 Cdn | |||||||||||
Jan 1, 2009 — Dec 31, 2009 | 6,000 | WTI(1) | $77.57 Cdn | |||||||||||
(1) | Associated Cdn $ / U.S. $ foreign exchange rate has been fixed |
Volume | Reference | Price | ||||||||||||
Remaining Term | (mmbtu/d) | Point | per mmbtu | |||||||||||
Financial: | ||||||||||||||
Jan 1, 2008 — Dec 31, 2008 | 5,000 | Transco Z6(1) | $10.90 Cdn | |||||||||||
Jan 1, 2008 — Dec 31, 2008 | 12,500 | NYMEX(1) | $8.22 Cdn | |||||||||||
Jan 1, 2009 — Dec 31, 2009 | 10,000 | NYMEX(1) | $8.50 Cdn | |||||||||||
Jan 1, 2008 — Mar 31, 2008 | 2,370 | AECO | $8.44 Cdn | |||||||||||
Jan 1, 2008 — Dec 31, 2008 | 61,609 | AECO | $8.26 Cdn | |||||||||||
Jan 1, 2009 — Dec 31, 2009 | 26,065 | AECO | $7.56 Cdn | |||||||||||
Jan 1, 2008 — Dec 31, 2008 | 15,000 | Chicago MI(1) | $8.45 Cdn | |||||||||||
Jan 1, 2009 — Dec 31, 2009 | 12,500 | Chicago MI(1) | $8.40 Cdn | |||||||||||
(1) | Associated Cdn $ / U.S. $ foreign exchange rate has been fixed |
Foreign | ||||||||||||||
Commodity risk | exchange risk | |||||||||||||
management | management | |||||||||||||
Balance Sheet as at December 31, 2007 | contracts | contracts | Total | |||||||||||
Current portion of unrealized risk management assets | $ | 8,034 | $ | — | $ | 8,034 | ||||||||
Non-current portion of unrealized risk management assets | 66 | 5,958 | 6,024 | |||||||||||
Current portion of unrealized risk management liabilities | (70,694 | ) | (152 | ) | (70,846 | ) | ||||||||
Non-current portion of unrealized risk management liabilities | (22,613 | ) | — | (22,613 | ) | |||||||||
Total unrealized risk management assets (liabilities) as at December 31, 2007 | $ | (85,207 | ) | $ | 5,806 | $ | (79,401 | ) | ||||||
Foreign | ||||||||||||||
Commodity risk | exchange risk | |||||||||||||
management | management | |||||||||||||
Balance Sheet as at December 31, 2006 | contracts | contracts | Total | |||||||||||
Current portion of unrealized risk management assets | $ | 37,972 | $ | — | $ | 37,972 | ||||||||
Non-current portion of unrealized risk management assets | 495 | — | 495 | |||||||||||
Current portion of unrealized risk management liabilities | — | — | — | |||||||||||
Non-current portion of unrealized risk management liabilities | (1,367 | ) | — | (1,367 | ) | |||||||||
Total unrealized risk management assets (liabilities) as at December 31, 2006 | $ | 37,100 | $ | — | $ | 37,100 | ||||||||
Foreign | ||||||||||||||
Commodity risk | exchange risk | |||||||||||||
management | management | |||||||||||||
Year ended December 31, 2007 | contracts | contracts | Total | |||||||||||
Total unrealized risk management assets (liabilities) at December 31, 2007 | $ | (85,207 | ) | $ | 5,806 | $ | (79,401 | ) | ||||||
Less: Unrealized risk management assets at January 1, 2007 | 37,100 | 13,873 | 50,973 | |||||||||||
Unrealized loss on risk management for the year ended December 31, 2007 | $ | (122,307 | ) | $ | (8,067 | ) | $ | (130,374 | ) | |||||
Foreign | ||||||||||||||
Commodity risk | exchange risk | |||||||||||||
management | management | |||||||||||||
Year ended December 31, 2006 | contracts | contracts | Total | |||||||||||
Total unrealized risk management assets at December 31, 2006 | $ | 37,100 | $ | — | $ | 37,100 | ||||||||
Less: Unrealized risk management asset recognized as part of Esprit business combination | 10,601 | — | 10,601 | |||||||||||
Unrealized gain on risk management for the year ended December 31, 2006 | $ | 26,499 | $ | — | $ | 26,499 | ||||||||
Volume | Price | |||||||||
Remaining Term 2008 to 2009 | (mmbtu/d) | per mmbtu(1) | ||||||||
Jan 1, 2008 — 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 |
2007 | 2006 | ||||||||||||||||||
Net book | Net book | ||||||||||||||||||
As at December 31 | Fair value | value | Fair value | value | |||||||||||||||
Remediation funds | $ | 18,107 | $ | 18,094 | $ | 11,162 | $ | 11,144 | |||||||||||
U.S. dollar denominated debt | $ | 627,674 | $ | 591,794 | $ | 224,624 | $ | 233,080 | |||||||||||
U.K. Pound Sterling denominated debt | $ | 96,181 | $ | 97,444 | $ | 109,692 | $ | 114,120 | |||||||||||
Convertible debentures | $ | 74,741 | $ | 75,030 | $ | 75,488 | $ | 75,127 | |||||||||||
2008 | 2009 | 2010 | 2011 | 2012 | Thereafter | Total | ||||||||||||||||||||||||
Operating leases | $ | 9,015 | $ | 9,232 | $ | 8,652 | $ | 8,221 | $ | 8,139 | $ | 42,028 | $ | 85,287 | ||||||||||||||||
Volume | Reference | Price | ||||||||||||
Remaining Term | (bbl/d) | Point | per bbl | |||||||||||
Financial: | ||||||||||||||
Mar 1, 2008 — Dec 31, 2008 | 1,500 | WTI(1) | $95.88Cdn | |||||||||||
Jan 1, 2009 — Dec 31, 2009 | 3,000 | WTI(1) | $93.25Cdn | |||||||||||
Volume | Reference | Price | ||||||||||||
Remaining Term | (mmbtu/d) | Point | per mmbtu | |||||||||||
Financial: | ||||||||||||||
Mar 1, 2008 — Dec 31, 2008 | 2,370 | AECO | $7.97Cdn | |||||||||||
Jan 1, 2009 — Dec 31, 2009 | 14,217 | AECO | $7.97Cdn | |||||||||||
Feb 1, 2008 — Dec 31, 2008 | 2,500 | Chicago MI (1) | $8.31Cdn | |||||||||||
(1) | Associated Cdn $ / U.S. $ foreign exchange rate has been fixed |
23. | RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES |
2007 | 2006 | ||||||||||||||||||
Number Exercised | Intrinsic Value | Number Exercised | Intrinsic Value | ||||||||||||||||
DEUs | 2,931 | (1) | $ | 58 | 14,523 | (1) | $ | 334 | |||||||||||
Trust Unit Options | 6,690 | 32 | 155,298 | 827 | |||||||||||||||
Trust Unit Rights | 343,925 | 2,837 | 452,468 | 3,924 | |||||||||||||||
Total | 353,546 | $ | 2,927 | 622,289 | $ | 5,085 | |||||||||||||
(1) | DEUs exercised relates to trust units issued under the plan for retirees as DEUs vest immediately upon retirement, including accumulated DRIP |
Trust Unit | Trust Unit | |||||||||||||
As at December 31, 2007 | Options | Rights | DEUs | |||||||||||
Number vested and expected to vest | 66,318 | 2,088,505 | 921,480 | |||||||||||
Weighted average exercise price per unit(1) | $ | 15.25 | $ | 17.26 | $ | — | ||||||||
Aggregate intrinsic value(2) | $ | 157 | $ | 756 | $ | 16,236 | ||||||||
Weighted average remaining life (years) | 0.8 | 3.3 | 1.5 | |||||||||||
(1) | No proceeds are received upon exercise price of DEUs | |
(2) | Based on December 31 closing trust unit price |
Trust Unit | Trust Unit | |||||||||||||
As at December 31, 2006 | Options | Rights | DEUs | |||||||||||
Number vested and expected to vest | 98,619 | 1,521,207 | 374,595 | |||||||||||
Weighted average exercise price per unit(1) | $ | 16.12 | $ | 16.04 | $ | — | ||||||||
Aggregate intrinsic value(2) | $ | 377 | $ | 5,936 | $ | 7,469 | ||||||||
Weighted average remaining life (years) | 1.5 | 3.2 | 1.8 | |||||||||||
(1) | No proceeds are received upon exercise price of DEUs | |
(2) | Based on December 31 closing trust unit price |
As at December 31, 2007 | Trust Unit Options | Trust Unit Rights | ||||||||
Number exercisable(1) | 66,318 | 1,317,296 | ||||||||
Weighted average exercise price per unit | $ | 15.25 | $ | 16.30 | ||||||
Aggregate intrinsic value(2) | $ | 157 | $ | 1,743 | ||||||
Weighted average remaining life (years) | 0.8 | 3.3 | ||||||||
(1) | No DEUs were exercisable at December 31, 2007 | |
(2) | Based on December 31 closing trust unit price |
As at December 31, 2006 | Trust Unit Options | Trust Unit Rights | ||||||||
Number exercisable(1) | 98,619 | 969,402 | ||||||||
Weighted average exercise price per unit | $ | 16.12 | $ | 14.22 | ||||||
Aggregate intrinsic value(2) | $ | 377 | $ | 5,542 | ||||||
Weighted average remaining life (years) | 1.5 | 3.2 | ||||||||
(1) | No DEUs were exercisable at December 31, 2006 | |
(2) | Based on December 31 closing trust unit price |
Pro Forma | ||||||
(unaudited) | ||||||
Oil and gas sales | $ | 1,458,370 | ||||
Net income | $ | 182,661 | ||||
Net income per trust unit: | ||||||
Basic | $ | 0.90 | ||||
Diluted | $ | 0.89 | ||||
2007 | ||||||
Balance, January 1 | $ | — | ||||
Additions based on tax positions related to the current year | 17,810 | |||||
Balance, December 31 | $ | 17,810 | ||||
Jurisdiction | Years | |||||
Federal(1) | 2004 — 2007 | |||||
Alberta, British Columbia, Saskatchewan and Nova Scotia | 2003 — 2007 | |||||
(1) | The 2004 tax examination by federal authorities is currently in progress |
Years ended December 31 | 2007 | 2006 | |||||||||
Net income, as reported | $ | 359,652 | $ | 262,303 | |||||||
Adjustments: | |||||||||||
Depletion and depreciation (a) | 35,761 | 23,997 | |||||||||
Ceiling test write down under U.S. GAAP (a) | — | (114,212 | ) | ||||||||
Unrealized gain (loss) on ineffective portion of oil and natural gas hedges (c) | — | 255 | |||||||||
Reclassification of hedging losses on foreign exchange swap from other comprehensive income (c) | — | 13,631 | |||||||||
Deferred foreign exchange loss (c) | (242 | ) | (13,631 | ) | |||||||
Non-cash interest on convertible debentures (g) | 69 | (29 | ) | ||||||||
Amortization of discontinued hedge (c) | 272 | — | |||||||||
Future tax adjustments (e)(i) | 69,040 | — | |||||||||
Net income — U.S. GAAP | $ | 464,552 | $ | 172,314 | |||||||
Other comprehensive income (b): | |||||||||||
Unrealized gain on foreign exchange swap (c) | — | 16,077 | |||||||||
Unrealized hedging gain (c) | — | 18,153 | |||||||||
Reclassification to net income (c) | — | (13,631 | ) | ||||||||
Amortization of discontinued hedge (c) | (272 | ) | — | ||||||||
Comprehensive income — U.S. GAAP | $ | 464,280 | $ | 192,913 | |||||||
Net income — U.S. GAAP — Basic and diluted | $ | 1.89 | $ | 0.98 | |||||||
As | Increase | |||||||||||||
As at December 31, 2007 | Reported | (Decrease) | U.S. GAAP | |||||||||||
Assets | ||||||||||||||
Property, plant and equipment (a) | $ | 4,306,682 | $ | (246,673 | ) | $ | 4,060,009 | |||||||
$ | (246,673 | ) | ||||||||||||
Liabilities | ||||||||||||||
Convertible debentures (g) | $ | 75,030 | $ | 120 | $ | 75,150 | ||||||||
Future income taxes (e) (i) | 387,100 | (86,850 | ) | 300,250 | ||||||||||
Other long term liabilities (i) | — | 17,810 | 17,810 | |||||||||||
Unitholders’ equity (d): | ||||||||||||||
Accumulated other comprehensive income (b)(c) | $ | — | $ | 2,174 | $ | 2,174 | ||||||||
Trust Unitholders’ Equity (a) | 2,756,220 | (179,927 | ) | 2,576,293 | ||||||||||
$ | (246,673 | ) | ||||||||||||
As | Increase | |||||||||||||
As at December 31, 2006 | Reported | (Decrease) | U.S. GAAP | |||||||||||
Assets | ||||||||||||||
Current portion of unrealized foreign exchange gain (c) | $ | — | $ | 1,559 | $ | 1,559 | ||||||||
Other assets (c) | 36,132 | (1,317 | ) | 34,815 | ||||||||||
Property, plant and equipment (a) | 3,741,602 | (282,434 | ) | 3,459,168 | ||||||||||
$ | (282,192 | ) | ||||||||||||
Liabilities | ||||||||||||||
Convertible debentures (g) | $ | 75,127 | $ | 189 | $ | 75,316 | ||||||||
Unitholders’ equity (d): | ||||||||||||||
Accumulated other comprehensive income (b)(c) | $ | — | $ | 2,446 | $ | 2,446 | ||||||||
Trust Unitholders’ Equity (a) | 3,049,677 | (284,827 | ) | 2,764,850 | ||||||||||
$ | (282,192 | ) | ||||||||||||
As at December 31 | 2007 | 2006 | ||||||||
Trade | $ | 179,253 | $ | 145,680 | ||||||
Prepaids | 27,330 | 23,972 | ||||||||
Other | — | 2,224 | ||||||||
$ | 206,583 | $ | 171,876 | |||||||
As at December 31 | 2007 | 2006 | ||||||||
Accounts payable | $ | 93,180 | $ | 93,788 | ||||||
Accrued liabilities | 145,911 | 127,425 | ||||||||
$ | 239,091 | $ | 221,213 | |||||||
ON CANADA-US REPORTING DIFFERENCES
Calgary, Canada
March 3, 2008
(unaudited)
(thousands of dollars) | 2007 | 2006 | ||||||
Revenue | ||||||||
Sales | $ | 1,422,148 | $ | 988,238 | ||||
Deduct | ||||||||
Production costs | 378,216 | 253,162 | ||||||
Transportation costs | 12,672 | 7,621 | ||||||
Amortization of injectant costs | 34,063 | 34,644 | ||||||
Technical support and other | 28,306 | 17,357 | ||||||
Depletion, depreciation and amortization | 603,323 | 327,578 | ||||||
Results of operations from producing activities | $ | 365,568 | $ | 347,876 | ||||
1. | The costs in this schedule exclude corporate overhead, interest expense and other operating costs which are not directly related to producing activities. |
2007 | 2006 | |||||||
(thousands of dollars) | ||||||||
Property Acquisition Costs | ||||||||
Proved | $ | 986,148 | $ | 1,333,666 | ||||
Unproved | 383,355 | 440,357 | ||||||
Exploration Costs | 21,192 | 8,900 | ||||||
Development Costs | 288,277 | 275,705 | ||||||
Injectant Costs | 26,052 | 34,630 | ||||||
$ | 1,705,024 | $ | 2,093,258 | |||||
(thousands of dollars) | 2007 | 2006 | ||||||
Oil and gas properties | $ | 6,578,258 | $ | 5,400,601 | ||||
Less accumulated depletion, depreciation and amortization | (2,540,283 | ) | (1,941,433 | ) | ||||
Net capitalized costs | $ | 4,037,975 | $ | 3,459,168 | ||||
(thousands of dollars) | 2007 | 2006 | ||||||
Unproven oil and gas properties | $ | 1,065,519 | $ | 471,820 | ||||
Proven oil and gas properties | 2,972,456 | 2,987,348 | ||||||
Net capitalized costs | $ | 4,037,975 | $ | 3,459,168 | ||||
Crude Oil | ||||||||
and Natural | Natural | |||||||
Gas Liquids | Gas | |||||||
MMbbls | Bcf | |||||||
NET PROVED DEVELOPED AND UNDEVELOPED RESERVES AFTER ROYALTIES | ||||||||
End of year 2005 | 88.2 | 333.5 | ||||||
Revision of previous estimates | 5.5 | 9.6 | ||||||
Purchase of reserves in place | 18.2 | 184.7 | ||||||
Sales of reserves in place | (0.4 | ) | (8.0 | ) | ||||
Discoveries and extensions | 0.8 | 23.9 | ||||||
Production | (10.1 | ) | (51.8 | ) | ||||
End of year 2006 | 102.2 | 491.9 | ||||||
Revision of previous estimates | 4.5 | 34.2 | ||||||
Purchase of reserves in place | 20.6 | 133.4 | ||||||
Sales of reserves in place | (4.3 | ) | (79.9 | ) | ||||
Discoveries and extensions | 1.1 | 27.1 | ||||||
Production | (12.6 | ) | (78.0 | ) | ||||
End of year 2007 | 111.5 | 528.7 | ||||||
NET PROVED DEVELOPED RESERVES AFTER ROYALTIES | ||||||||
End of year 2005 | 70.4 | 309.3 | ||||||
End of year 2006 | 84.1 | 453.1 | ||||||
End of year 2007 | 93.0 | 474.9 |
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. |
2007 | 2006 | |||||||
(millions of dollars) | ||||||||
Future cash inflows | $ | 12,796 | $ | 9,480 | ||||
Future costs | ||||||||
Future production and development costs | (4,957 | ) | (4,162 | ) | ||||
Future income taxes (1) | (2,000 | ) | — | |||||
Future net cash flows | 5,839 | 5,318 | ||||||
Deduct: 10% annual discount factor | (2,149 | ) | (2,152 | ) | ||||
Standardized measure of discounted future net cash flows | $ | 3,690 | $ | 3,166 | ||||
2007 | 2006 | |||||||
(millions of dollars) | ||||||||
Future discounted net cash flows at beginning of year | $ | 3,166 | $ | 3,344 | ||||
Sales and transfer, net of production costs | (970 | ) | (676 | ) | ||||
Net change in sales and transfer prices, net of production costs | 1,111 | (637 | ) | |||||
Development costs during the year | 271 | 284 | ||||||
Changes in estimated future development costs | (346 | ) | (355 | ) | ||||
Changes due to extensions and discoveries | 130 | 83 | ||||||
Changes due to revisions (including infill drilling and improved recovery) | 234 | 129 | ||||||
Accretion of discount | 317 | 334 | ||||||
Sales of reserves in place | (303 | ) | (40 | ) | ||||
Purchase of reserves in place | 983 | 842 | ||||||
Net changes in income taxes | (895 | ) | — | |||||
Changes in timing of future net cash flows and other | (8 | ) | (142 | ) | ||||
End of Year | $ | 3,690 | $ | 3,166 | ||||
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. |
DATED FEBRUARY 19, 2008
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Application | 1 | |||
Purpose | 1 | |||
Policy | 1 | |||
Compliance with the Law | 2 | |||
Health, Safety and the Environment | 3 | |||
Public Reporting | 3 | |||
Conflict of Interest | 4 | |||
Private Business | 5 | |||
Payments | 5 | |||
Political Contributions | 6 | |||
Involvement with Not-for-Profit Organizations | 6 | |||
Outside Employment | 6 | |||
Directorships | 7 | |||
Government Relations | 7 | |||
Confidential Information | 7 | |||
Company Information | 7 | |||
Inside Information | 8 | |||
Books of Account | 9 | |||
Patents and Inventions | 9 | |||
Community Relations | 9 | |||
Company Property and Opportunities | 10 | |||
Accounting and Financial Reporting | 10 | |||
Employee Relations and Reporting | 10 | |||
Policies, Procedures and Internal Controls | 10 | |||
Acknowledgement | 11 | |||
Exceptions and Changes | 11 | |||
Appendix “A” Complaint Procedures For Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics | 12 | |||
Appendix “B” Awareness Statement on Code of Business Conduct and Ethics | 15 |
• | assure compliance with laws and regulations that govern the business activities of Pengrowth; | ||
• | maintain a corporate climate in which the integrity and dignity of each individual is valued; | ||
• | foster a standard of conduct that reflects positively on Pengrowth; and | ||
• | protect Pengrowth from unnecessary exposure to financial loss. |
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• | all accounting records, and the reports produced from such records, must be in accordance with all applicable laws; | ||
• | all accounting records must fairly and accurately reflect the transactions or occurrences to which they relate; | ||
• | all accounting records must fairly and accurately reflect in reasonable detail Pengrowth’s assets, liabilities, revenues and expenses; | ||
• | no accounting records should contain any false or intentionally misleading entries; | ||
• | no transactions should be intentionally misclassified as to accounts, departments or accounting periods; | ||
• | all transactions must be supported by accurate documentation in reasonable detail and recorded in the proper account and in the proper accounting period; | ||
• | no information should be concealed from the internal auditors or the independent auditors; and | ||
• | compliance with Pengrowth’s system of internal controls is required. |
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Ø | they are not in cash or securities and are of nominal value; | ||
Ø | they do not contravene any law and are made as a matter of general and accepted practice or in accordance with corporate policy; and | ||
Ø | if subsequently disclosed to the public, they would not in any way embarrass Pengrowth or their recipients. |
(a) | any such contribution may only be made to a political party and not to an individual candidate for election to public office; | ||
(b) | any such contribution requires the approval of the Chief Executive Officer; and | ||
(c) | any such contribution must be within the approved operating budget of Pengrowth. |
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Complaint Procedures
For Accounting, Financial Reporting and Auditing Matters
and Violations of the Code of Business Conduct and Ethics
• | Directors, officers and employees with concerns regarding Accounting Matters may report their concerns to the Chairman of the Audit Committee. |
• | Directors, officers, employees, consultants or contractors with concerns regarding Conduct Matter may report their concerns to the Chairman of the Corporate Governance Committee. |
• | Directors, officers and employees may report concerns regarding Accounting Matters or Conduct Matters on a confidential or anonymous basis to Grant Thornton LLP, at 1-888-747-7171 or usecare@GrantThornton.ca. |
• | A director, officer or employee who makes an anonymous submission must be sure to provide sufficient detail to identify the concern being raised. Because the submission is made anonymously, the Audit Committee or the Corporate Governance Committee, as the case may be, will be unable to follow up if there are additional questions. The complaint should, at a minimum, contain dates, places, persons involved and witnesses such that a reasonable investigation or assessment can be conducted. |
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• | fraud or deliberate error in the preparation, evaluation, review or audit of any financial statement of Pengrowth; |
• | fraud or deliberate error in the recording and maintaining of financial records of Pengrowth; |
• | deficiencies in or non-compliance with Pengrowth’s internal accounting controls; |
• | misrepresentation or false statement to or by a director, officer, employee or external accountant regarding a matter contained in the financial records, financial reports or audit reports of Pengrowth; or |
• | deviation from full and fair reporting of Pengrowth’s financial condition. |
• | Grant Thornton LLP shall inform (i) the Chairman of the Audit Committee of all complaints and concerns provided to it in respect of Accounting Matters; and (ii) the Chairman of the Corporate Governance Committee of all complaints provided to it in respect of Conduct Matters. |
• | Upon receipt of a complaint or concern, the Chairman of the Audit Committee or Chairman of the Corporate Governance Committee, as the case may be, will (i) determine whether or not the complaint actually pertains to Accounting Matters or Conduct Matters and (ii) when possible, acknowledge receipt of the complaint to the sender. |
• | Complaints relating to Accounting Matters will be reviewed by the Audit Committee, outside legal counsel or such other persons as the Audit Committee determines to be appropriate. Complaints relating to Conduct Matters will be reviewed by the Corporate Governance Committee, outside legal counsel and such other persons as the Corporate Governance Committee determines to be appropriate. In any case, confidentiality will be maintained to the fullest extent possible, consistent with the need to conduct an adequate review. |
• | Prompt and appropriate corrective action will be taken when and as warranted in the judgment of the Audit Committee or the Corporate Governance Committee, as the case may be. |
• | Pengrowth will not discharge, demote, suspend, threaten, harass or in any manner discriminate against any individual in the terms and conditions of employment based upon any lawful actions of such individual with respect to reporting of complaints in good faith regarding Accounting Matters or Conduct Matters. |
• | Pengrowth will regard the making of any deliberately false or malicious allegations by an employee as a serious offence which may result in recommendations to the Board or to senior management of Pengrowth for disciplinary action including dismissal for cause and, if warranted, legal proceedings. |
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• | The Chairman of the Audit Committee and the Chairman of the Corporate Governance Committee will maintain a log of all complaints, tracking their receipt, investigation and resolution and shall prepare a periodic summary report thereof for the Audit Committee or the Corporate Governance Committee, as the case may be. |
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Awareness Statement on Code of Business Conduct and Ethics
To be completed by all directors, officers, employees, consultants and contractors
of Pengrowth Energy Trust and its subsidiaries (“Pengrowth”)
1. | I understand the content and consequences of contravening the Code and agree to abide by the Code. |
2. | I am in compliance with the Code. |
3. | All facts and dealings which I believe to be non-compliant with the Code have been communicated to the appropriate representative of Pengrowth and are detailed below. |
4. | (If applicable) After due inquiry and to my best knowledge and belief, no employee, consultant or contractor under my direct supervision is in violation of the Code. |
5. | I have and will continue to exercise my best efforts to assure full compliance with the Code by myself and (if applicable) all employees, consultants and contractors under my direct supervision. |
Print or type name: | ||||||
Signature: | ||||||
Title and location: | ||||||
Date: | ||||||
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