o | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934 |
þ | ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
1311 | None | |
(Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification Number) |
Title of each class | Name of each exchange on which registered | |
Common Shares | New York Stock Exchange |
Date: February 28, 2018 | PENGROWTH ENERGY CORPORATION | |||
By: | /s/ Derek W. Evans | |||
Name: Derek W. Evans | ||||
Title: President and Chief Executive Officer | ||||
Exhibit | Description | |
99.1 | Pengrowth Energy Corporation Annual Information Form for the year ended December 31, 2017 | |
99.2 | Management’s Discussion and Analysis for the fiscal year ended December 31, 2017 | |
99.3 | Consolidated Financial Statements of Pengrowth Energy Corporation for the fiscal year ended December 31, 2017, including Management’s Report to Shareholders and the Auditors’ Reports | |
99.4 | Supplemental Unaudited Disclosures about Oil and Gas Producing Activities required under United States Generally Accepted Accounting Principles | |
99.5 | Consent of Independent Registered Public Accounting Firm | |
99.6 | Consent of GLJ Petroleum Consultants Ltd. | |
99.7 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 | |
99.8 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 | |
99.9 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 | |
99.10 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 | |
GLOSSARY OF TERMS AND ABBREVIATIONS | |
CONVERSION | |
PRESENTATION OF OUR FINANCIAL INFORMATION | |
PRESENTATION OF OUR RESERVE AND RESOURCE INFORMATION | |
FORWARD-LOOKING STATEMENTS | |
PENGROWTH ENERGY CORPORATION | |
Introduction | |
General Development of the Business | |
DESCRIPTION OF OUR BUSINESS | |
General | |
Business Strategy | |
OPERATIONAL INFORMATION | |
Principal Producing Properties | |
Statement of Oil and Gas Reserves and Reserves Data | |
Additional Information Relating to Reserves Data | |
Significant Factors or Uncertainties Affecting Reserves Data | |
Future Development Costs | |
Finding, Development and Acquisition Costs | |
Recycle Ratio | |
Reserve Life Index | |
Reserve Replacement | |
Other Oil and Gas Information | |
Forward Contracts | |
Tax Horizon | |
Costs Incurred | |
Exploration and Development Activities | |
Production Estimates | |
Production History (Netback) | |
DESCRIPTION OF CAPITAL STRUCTURE | |
DIVIDENDS | |
INDUSTRY CONDITIONS | |
RISK FACTORS | |
MARKET FOR SECURITIES | |
DIRECTORS AND OFFICERS | |
Corporate Cease Trade Orders, Bankruptcies, Personal Bankruptcies, Penalties or Sanctions | |
AUDIT AND RISK COMMITTEE | |
Principal Accountant Fees and Services | |
Pre-approval Policies and Procedures | |
CONFLICTS OF INTEREST | |
LEGAL PROCEEDINGS | |
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS | |
INTERESTS OF EXPERTS | |
AUDITORS, TRANSFER AGENT AND REGISTRAR | |
MATERIAL CONTRACTS | |
CODE OF ETHICS | |
OFF-BALANCE SHEET ARRANGEMENTS | |
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE | |
ADDITIONAL INFORMATION | |
APPENDIX A - Supplemental Disclosure - Contingent Resources | |
APPENDIX B - Report on Reserves Data and Contingent Resources Data by Independent Qualified Reserves Evaluator (Form 51-101F2) | |
APPENDIX C - Report of Management and Directors on Oil and Gas Disclosure (Form 51-101F3) | |
APPENDIX D - Audit and Risk Committee Terms of Reference | |
Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2017 |
To Convert From | To | Multiply by |
Mcf | cubic metre | 28.174 |
Mcf | BOE | 0.1667 |
bbl | BOE | 1.0 |
MMBtu | gigajoule | 1.0546 |
cubic metre | bbl | 6.29 |
metre | feet | 3.281 |
mile | kilometre | 1.609 |
hectare | acre | 2.471 |
P+P | Remaining | P+P Reserve | P+P Value Before Tax | 2017 Oil | 2017 Bitumen | 2017 Gas | 2017 Shale Gas | 2017 NGL | 2017 Total | |
Reserves | Reserve Life | Life Index | Discounted at 10%(4) | Production | Production | Production | Production | Production | Production | |
Field | (Mboe(3)) | (years) | (years) | ($MM) | (bbl/d) | (bbl/d) | (MMcf/d) | (MMcf/d) | (bbl/d) | (BOE/d(3)) |
Lindbergh | 317,057 | 26 | 44.5 | 1,763,534 | - | 13,754 | - | - | - | 13,754 |
Groundbirch | 124,409 | 50 | 133.8 | 346,491 | - | - | - | 10.4 | - | 1,729 |
Subtotal | 441,466 | 50 | 54.9 | 2,110,025 | - | 13,754 | - | 10.4 | - | 15,483 |
Remainder(5) | 5,166 | 50 | 4.9 | 60,251 | 6,872.1 | - | 81 | - | 4,573.8 | 24,945 |
Total | 446,632 | 50 | 49.0 | 2,170,276 | 6,872.1 | 13,754 | 81 | 10.4 | 4,573.8 | 40,428 |
(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) | Forecast prices are shown under the heading "Pricing Assumptions". |
(3) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. |
(4) | Estimated Future Net Revenues disclosed do not represent fair market value. |
(5) | "Remainder" includes our Working Interests and Royalty Interests in 16 other properties. |
• | Corporate income tax at the current legislated rate; |
• | Annual general and administrative expenses at the current rate; |
• | Interest expense at the current rate; |
• | Tax pool deductions utilizing our existing $2.4 billion of tax pools and forecasted additions to our tax pools from capital expenditures as forecast by GLJ; and |
• | Any such other additional deductions and adjustments as is and would be consistent with the manner in which we file and would file future tax returns. |
Light Crude Oil and Medium Crude Oil | Heavy Crude Oil | Bitumen | Natural Gas Liquids | ||||||||||||
Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | ||||
Reserves Category | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | |||
Proved Reserves | |||||||||||||||
Proved Developed Producing | 1,976 | 1,975 | 1,774 | - | - | - | 24,733 | 24,733 | 22,721 | 97 | 96 | 84 | |||
Proved Developed Non-Producing | 57 | 56 | 54 | - | - | - | - | - | - | 43 | 42 | 34 | |||
Proved Undeveloped | 6 | 6 | 5 | - | - | - | 138,600 | 138,600 | 106,621 | 2 | 2 | 2 | |||
Total Proved Reserves | 2,038 | 2,037 | 1,833 | - | - | - | 163,334 | 163,334 | 129,342 | 142 | 141 | 121 | |||
Probable Reserves | 673 | 672 | 603 | - | - | - | 153,724 | 153,724 | 116,620 | 29 | 29 | 25 | |||
Total Proved Plus Probable Reserves | 2,712 | 2,709 | 2,437 | - | - | - | 317,057 | 317,057 | 245,961 | 171 | 170 | 145 |
Conventional Natural Gas | Shale Gas | Coal Bed Methane | Total Oil Equivalent Basis(2) | ||||||||||||
Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | ||||
Reserves Category | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mboe) | (Mboe) | (Mboe) | |||
Proved Reserves | |||||||||||||||
Proved Developed Producing | 4,776 | 4,630 | 4,324 | 31,354 | 31,354 | 29,490 | 2,582 | 2,500 | 2,412 | 33,257 | 33,218 | 30,617 | |||
Proved Developed Non-Producing | 2,117 | 2,059 | 1,829 | - | - | - | 646 | 646 | 595 | 560 | 549 | 492 | |||
Proved Undeveloped | - | - | - | 121,493 | 121,493 | 106,297 | 258 | 258 | 245 | 158,900 | 158,900 | 124,385 | |||
Total Proved Reserves | 6,892 | 6,689 | 6,154 | 152,847 | 152,847 | 135,786 | 3,486 | 3,404 | 3,251 | 192,718 | 192,668 | 155,494 | |||
Probable Reserves | 1,339 | 1,262 | 1,202 | 593,606 | 593,606 | 500,802 | 1,980 | 1,943 | 1,865 | 253,914 | 253,894 | 201,226 | |||
Total Proved Plus Probable Reserves | 8,231 | 7,951 | 7,356 | 746,452 | 746,452 | 636,588 | 5,465 | 5,348 | 5,116 | 446,632 | 446,561 | 356,720 |
(1) | Forecast prices are shown under the heading "Pricing Assumptions". |
(2) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. |
Before Income Taxes Discounted at (%/year) - $MM | Unit Value Before Income Tax Discounted at 10%/year(2) (3) | ||||||||||||
Reserves Category | 0 | % | 5 | % | 10 | % | 15 | % | 20 | % | $/BOE | $/McfGE | |
Proved Reserves | |||||||||||||
Proved Developed Producing | 568 | 516 | 472 | 433 | 400 | 15.40 | 2.57 | ||||||
Proved Developed Non-Producing | 4 | 2 | 1 | 1 | 1 | 2.42 | 0.40 | ||||||
Proved Undeveloped | 3,102 | 1,442 | 759 | 435 | 263 | 6.10 | 1.02 | ||||||
Total Proved Reserves | 3,674 | 1,960 | 1,231 | 869 | 663 | 7.92 | 1.32 | ||||||
Probable Reserves | 4,417 | 2,016 | 939 | 415 | 146 | 4.67 | 0.78 | ||||||
Total Proved Plus Probable Reserves | 8,090 | 3,976 | 2,170 | 1,285 | 809 | 6.08 | 1.01 |
After Income Taxes Discounted at (%/year)(4) - $MM | |||||||||||||
Reserves Category | 0 | % | 5 | % | 10 | % | 15 | % | 20 | % | |||
Proved Reserves | |||||||||||||
Proved Developed Producing | 568 | 516 | 472 | 433 | 400 | ||||||||
Proved Developed Non-Producing | 4 | 2 | 1 | 1 | 1 | ||||||||
Proved Undeveloped | 2,477 | 1,290 | 718 | 421 | 255 | ||||||||
Total Proved Reserves | 3,049 | 1,807 | 1,191 | 855 | 656 | ||||||||
Probable Reserves | 3,029 | 1,380 | 617 | 242 | 48 | ||||||||
Total Proved Plus Probable Reserves | 6,078 | 3,187 | 1,808 | 1,097 | 701 |
(1) | Forecast prices are shown under the heading "Pricing Assumptions". |
(2) | Net present value of Future Net Revenue per reserve unit values are based on our net reserves. |
(3) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. Oil and NGL have been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or NGL being equal to six (6) Mcf of natural gas. |
(4) | After-tax values were calculated using current corporate tax rates, existing tax pools and additions to the tax pools through capital expenditures as forecast by GLJ. See – "Operational Information - Statement of Oil and Gas Reserves and Reserves Data – Disclosure of Reserves Data" for additional descriptions of the assumptions made in calculating the after-tax values. |
Reserves Category | Revenue | Royalties(2) | Operating Costs | Development Costs | Abandonment and Reclamation Costs(3) | Future Net Revenue Before Income Taxes | Income Tax | Future Net Revenue After Income Taxes |
Total Proved | 12,132 | 2,580 | 3,602 | 1,932 | 344 | 3,674 | 624 | 3,050 |
Total Proved Plus Probable | 24,951 | 5,574 | 5,745 | 4,941 | 601 | 8,090 | 2,012 | 6,078 |
(1) | Forecast prices are shown under the heading "Pricing Assumptions". |
(2) | Crown royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia, freehold and over-riding royalties payable and other minor burdens. |
(3) | Includes GLJ’s forecast of well abandonment and reclamation costs, abandonment of Sable Island facilities and subsea pipelines and abandonment and reclamation of the Lindbergh central processing facility, based on estimates by the Corporation, but does not include abandonment and surface reclamation costs for any other facilities. See "Operational Information – Significant Factors or Uncertainties Affecting Reserves Data - Additional Information Concerning Abandonment & Reclamation Costs". |
Future Net Revenue Before Income Taxes (discounted at 10%/year) | Unit Value(4)(5) | ||||
Reserves Category | Product Type | ($MM) | ($/BOE) | ($/McfGE) | |
Total Proved | Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2) | 33 | 16.30 | 2.72 | |
Heavy Crude Oil (including solution gas and other by-products)(2) | - | - | - | ||
Bitumen | 1,098 | 8.49 | 1.42 | ||
Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3) | 2 | 2.41 | 0.40 | ||
Shale Gas | 97 | 4.31 | 0.72 | ||
Coal Bed Methane | - | 0.76 | 0.13 | ||
Total | 1,231 | 7.92 | 1.32 | ||
Total Proved Plus Probable | Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2) | 41 | 15.22 | 2.54 | |
Heavy Crude Oil (including solution gas and other by-products)(2) | - | - | - | ||
Bitumen | 1,713 | 6.97 | 1.16 | ||
Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3) | 4 | 3.64 | 0.61 | ||
Shale Gas | 411 | 3.87 | 0.65 | ||
Coal Bed Methane | 1 | 1.49 | 0.25 | ||
Total | 2,170 | 6.08 | 1.01 |
(1) | Forecast prices are shown under the heading "Pricing Assumptions". |
(2) | NGL associated with the production of solution gas are included as a by-product. |
(3) | NGL associated with the production of natural gas are included as a by-product. |
(4) | Net present value of Future Net Revenue per BOE or McfGE are based on our net reserves. |
(5) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. Oil and NGL have been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or NGL being equal to six (6) Mcf of natural gas. |
Light Crude Oil and Medium Crude Oil | Heavy Crude Oil | Bitumen | Natural Gas Liquids | |||||||||||||||||||||
Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | |||||||||||||
Reserves Category | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
Proved Reserves | ||||||||||||||||||||||||
Proved Developed Producing | 1,794 | 1,793 | 1,614 | - | - | - | 24,012 | 24,012 | 22,355 | 90 | 90 | 79 | ||||||||||||
Proved Developed Non-Producing | 55 | 54 | 52 | - | - | - | - | - | - | 9 | 9 | 8 | ||||||||||||
Proved Undeveloped | 5 | 5 | 4 | - | - | - | 138,314 | 138,314 | 121,870 | 2 | 2 | 2 | ||||||||||||
Total Proved Reserves | 1,853 | 1,852 | 1,670 | - | - | - | 162,327 | 162,327 | 144,225 | 102 | 101 | 89 | ||||||||||||
Probable Reserves | 601 | 600 | 541 | - | - | - | 154,731 | 154,731 | 132,819 | 18 | 18 | 16 | ||||||||||||
Total Proved Plus Probable Reserves | 2,454 | 2,452 | 2,211 | - | - | - | 317,057 | 317,057 | 277,044 | 120 | 119 | 104 |
Conventional Natural Gas | Shale Gas | Coal Bed Methane | Total Oil Equivalent Basis(2) | ||||||||||||||||||||||||
Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | Company Interest | Gross Interest | Net Interest | ||||||||||||||||
Reserves Category | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mboe) | (Mboe) | (Mboe) | |||||||||||||||
Proved Reserves | |||||||||||||||||||||||||||
Proved Developed Producing | 4,177 | 4,135 | 3,817 | 25,573 | 25,573 | 24,807 | 1,567 | 1,522 | 1,465 | 31,115 | 31,100 | 29,062 | |||||||||||||||
Proved Developed Non-Producing | 728 | 694 | 660 | - | - | - | 498 | 498 | 465 | 268 | 262 | 247 | |||||||||||||||
Proved Undeveloped | - | - | - | 120,569 | 120,569 | 111,119 | - | - | - | 158,417 | 157,417 | 140,396 | |||||||||||||||
Total Proved Reserves | 4,905 | 4,829 | 4,476 | 146,143 | 146,143 | 135,926 | 2,065 | 2,020 | 1,930 | 189,800 | 189,778 | 169,706 | |||||||||||||||
Probable Reserves | 707 | 700 | 655 | 585,179 | 585,179 | 522,089 | 501 | 496 | 464 | 253,081 | 253,078 | 220,577 | |||||||||||||||
Total Proved Plus Probable Reserves | 5,612 | 5,529 | 5,131 | 731,322 | 731,322 | 658,015 | 2,566 | 2,516 | 2,393 | 442,882 | 442,856 | 390,282 |
(1) | Constant prices are shown under the heading "Pricing Assumptions". |
(2) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. |
Before Income Taxes Discounted at (%/year) - $MM | Unit Value Before Income Taxes Discounted at 10%/year(2)(3) | ||||||||||||||
Reserves Category | 0 | % | 5 | % | 10 | % | 15 | % | 20 | % | $/BOE | $/McfGE | |||
Proved Reserves | |||||||||||||||
Proved Developed Producing | 519 | 489 | 458 | 429 | 403 | 15.76 | 2.63 | ||||||||
Proved Developed Non-Producing | 58 | 132 | 146 | 137 | 120 | 0.59 | 0.1 | ||||||||
Proved Undeveloped | 954 | 391 | 142 | 24 | (33 | ) | 2.05 | 0.34 | |||||||
Total Proved Reserves | 1,531 | 1,012 | 746 | 590 | 490 | 4.39 | 0.73 | ||||||||
Probable Reserves | 1,664 | 583 | 123 | (86 | ) | (182 | ) | 0.56 | 0.09 | ||||||
Total Proved Plus Probable Reserves | 3,195 | 1,595 | 868 | 505 | 308 | 2.22 | 0.37 |
After Income Taxes Discounted at (%/year)(4) - $MM | |||||||||||||
Reserves Category | 0 | % | 5 | % | 10 | % | 15 | % | 20 | % | |||
Proved Reserves | |||||||||||||
Proved Developed Producing | 519 | 489 | 458 | 429 | 403 | ||||||||
Proved Developed Non-Producing | 58 | 132 | 146 | 137 | 120 | ||||||||
Proved Undeveloped | 942 | 400 | 138 | 27 | (33 | ) | |||||||
Total Proved Reserves | 1,520 | 1,021 | 742 | 593 | 490 | ||||||||
Probable Reserves | 1,061 | 331 | 15 | (145 | ) | (214 | ) | ||||||
Total Proved Plus Probable Reserves | 2,581 | 1,352 | 757 | 448 | 276 |
(1) | Constant prices are shown under the heading "Pricing Assumptions". |
(2) | Net present value of Future Net Revenue per reserve unit values are based on our net reserves. |
(3) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. Oil and NGL have been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or NGL being equal to six (6) Mcf of natural gas. |
(4) | After-tax values were calculated using current corporate tax rates, existing tax pools and additions to the tax pools through capital expenditures as forecast by GLJ. See – "Operational Information - Statement of Oil and Gas Reserves and Reserves Data – Disclosure of Reserves Data" for additional descriptions of the assumptions made in calculating the after-tax values. |
Reserves Category | Revenue | Royalties(2) | Operating Costs | Development Costs | Abandonment and Reclamation Costs(3) | Future Net Revenue Before Income Taxes | Income Tax | Future Net Revenue After Income Taxes |
Total Proved | 6,837 | 730 | 2,400 | 1,919 | 257 | 1,531 | 12 | 1,519 |
Total Proved Plus Probable | 14,306 | 1,732 | 4,058 | 4,897 | 424 | 3,195 | 616 | 2,579 |
(1) | Constant prices are shown under the heading "Pricing Assumptions". |
(2) | Crown royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia, freehold and over-riding royalties payable and other minor burdens. |
(3) | Includes GLJ’s forecast of well abandonment and reclamation costs, abandonment of Sable Island facilities and subsea pipelines, and abandonment and reclamation of the Lindbergh central processing facilities, based on estimates by the Corporation, but does not include abandonment and surface reclamation costs for any other facilities. See "Operational Information – Significant Factors or Uncertainties Affecting Reserves Data - Additional Information Concerning Abandonment & Reclamation Costs". |
Future Net Revenue Before Income Taxes (discounted at 10%/year) | Unit Value(4)(5) | ||||||
Reserves Category | Product Type | ($MM) | ($/BOE) | ($/McfGE) | |||
Total Proved | Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2) | 23 | 12.27 | 2.04 | |||
Heavy Crude Oil (including solution gas and other by-products)(2) | - | - | - | ||||
Bitumen | 687 | 4.76 | 0.79 | ||||
Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3) | (1 | ) | (2.26 | ) | (0.38) | ||
Shale Gas | 38 | 1.69 | 0.28 | ||||
Coal Bed Methane | (1 | ) | (2.17 | ) | (0.36) | ||
Total | 746 | 4.39 | 0.73 | ||||
Total Proved Plus Probable | Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2) | 27 | 10.96 | 1.83 | |||
Heavy Crude Oil (including solution gas and other by-products)(2) | - | - | - | ||||
Bitumen | 672 | 2.43 | 0.40 | ||||
Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3) | - | (0.56 | ) | (0.09) | |||
Shale Gas | 170 | 1.55 | 0.26 | ||||
Coal Bed Methane | - | (1.22 | ) | (0.20) | |||
Total | 868 | 2.22 | 0.37 |
(1) | Constant prices are shown under the heading "Pricing Assumptions". |
(2) | NGL associated with the production of solution gas are included as a by-product. |
(3) | NGL associated with the production of natural gas are included as a by-product. |
(4) | Net present value of Future Net Revenue per BOE or McfGE are based on our net reserves. |
(5) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. Oil and NGL have been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or NGL being equal to six (6) Mcf of natural gas. |
Oil | Natural Gas | Natural Gas Liquids(1) | ||||||||||||
WTI Cushing Oklahoma | Edmonton Par Price 40°API | Cromer Medium 29°API | WCS Stream Quality | Hardisty Heavy 12°API | Lindbergh Bitumen Wellhead Calculated(5) | AECO Gas Price | Propane | Butane | Pentanes Plus | Inflation Rates(2) | Exchange Rate(3) | |||
Year | (US$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/MMBtu) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (%/year) | (US$/Cdn$) | ||
2017(4) | 50.88 | 62.78 | 59.90 | 50.46 | 44.56 | 33.28 | 2.16 | 28.64 | 44.58 | 66.80 | 1.6 | 0.7711 | ||
2018 | 59.00 | 70.25 | 65.34 | 48.89 | 39.63 | 32.18 | 2.20 | 40.40 | 53.74 | 76.42 | 2.0 | 0.7900 | ||
2019 | 59.00 | 70.25 | 65.34 | 53.16 | 45.71 | 39.04 | 2.54 | 36.53 | 49.18 | 74.68 | 2.0 | 0.7900 | ||
2020 | 60.00 | 70.31 | 65.39 | 56.25 | 49.81 | 43.58 | 2.88 | 35.93 | 49.22 | 74.38 | 2.0 | 0.8000 | ||
2021 | 63.00 | 72.84 | 67.74 | 59.26 | 52.89 | 46.69 | 3.24 | 36.06 | 50.99 | 77.16 | 2.0 | 0.8100 | ||
2022 | 66.00 | 75.61 | 70.32 | 62.20 | 55.89 | 49.72 | 3.47 | 36.29 | 52.93 | 79.88 | 2.0 | 0.8200 | ||
2023 | 69.00 | 78.31 | 72.83 | 65.06 | 58.82 | 52.67 | 3.58 | 37.59 | 54.82 | 82.53 | 2.0 | 0.8300 | ||
2024 | 72.00 | 81.93 | 76.19 | 68.67 | 62.43 | 56.29 | 3.66 | 39.33 | 57.35 | 86.14 | 2.0 | 0.8300 | ||
2025 | 75.00 | 85.54 | 79.55 | 72.29 | 66.05 | 59.90 | 3.73 | 41.06 | 59.88 | 89.76 | 2.0 | 0.8300 | ||
2026 | 77.33 | 88.35 | 82.16 | 75.10 | 68.86 | 62.61 | 3.80 | 42.41 | 61.84 | 92.57 | 2.0 | 0.8300 | ||
2027 | 78.88 | 90.22 | 83.90 | 76.96 | 70.72 | 64.38 | 3.88 | 43.30 | 63.15 | 94.43 | 2.0 | 0.8300 | ||
thereafter | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | 2.0 | 0.8300 |
(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 historical prices for 2017. |
(5) | Lindbergh forecast wellhead prices are calculated accounting for all diluent/blending and transportation costs. |
Oil | Natural Gas | Natural Gas Liquids(1) | ||||||||||||
WTI Cushing Oklahoma | Edmonton Par Price 40°API | Cromer Medium 29°API | WCS Stream Quality | Hardisty Heavy 12°API | Lindbergh Bitumen Wellhead Calculated(2) | AECO Gas Price | Propane | Butane | Pentanes Plus | Inflation Rate | Exchange Rate | |||
Year | (US$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/MMBtu) | (Cdn$/bbl) | (Cdn$/bbl) | (Cdn$/bbl) | (%/year) | (US$/Cdn$) | ||
2018 and thereafter | 51.03 | 63.43 | 60.55 | 51.09 | 45.18 | 39.18 | 2.35 | 28.38 | 44.70 | 67.46 | 0.0 | 0.7690 |
(1) | FOB Edmonton. |
(2) | Lindbergh constant wellhead price is calculated accounting for all diluent/blending and transportation costs. |
Light Crude Oil and Medium Crude Oil | Heavy Crude Oil | Bitumen | Natural Gas Liquids | ||||||||||||||||||||||||
Proved | Probable | Proved Plus Probable | Proved | Probable | Proved Plus Probable | Proved | Probable | Proved Plus Probable | Proved | Probable | Proved Plus Probable | ||||||||||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||||||
December 31, 2016 | 40,110 | 16,828 | 56,938 | 2 | 1 | 4 | 146,265 | 171,640 | 317,905 | 24,439 | 11,633 | 36,073 | |||||||||||||||
Extensions & Improved Recovery | - | - | - | - | - | - | 16,542 | (16,542 | ) | - | - | - | - | ||||||||||||||
Infill Drilling | - | - | - | - | - | - | 1,325 | (1,325 | ) | - | - | - | - | ||||||||||||||
Technical Revisions | (181 | ) | (149 | ) | (330 | ) | - | - | - | 4,221 | (49 | ) | 4,172 | 164 | (91 | ) | 73 | ||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||
Dispositions | (35,330 | ) | (16,000 | ) | (51,330 | ) | (2 | ) | (1 | ) | (3 | ) | - | - | - | (22,781 | ) | (11,506 | ) | (34,287 | ) | ||||||
Economic Factors | (62 | ) | (7 | ) | (69 | ) | - | - | - | - | - | - | (21 | ) | (8 | ) | (29 | ) | |||||||||
Production | (2,501 | ) | - | (2,501 | ) | - | - | - | (5,020 | ) | - | (5,020 | ) | (1,661 | ) | - | (1,661 | ) | |||||||||
December 31, 2017 | 2,037 | 672 | 2,709 | - | - | - | 163,334 | 153,724 | 317,057 | 141 | 29 | 170 |
Conventional Natural Gas | Shale Gas | Coal Bed Methane | Total Oil Equivalent Basis(1) | ||||||||||||||||||||||||
Proved | Probable | Proved Plus Probable | Proved | Probable | Proved Plus Probable | Proved | Probable | Proved Plus Probable | Proved | Probable | Proved Plus Probable | ||||||||||||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||
December 31, 2016 | 311,992 | 141,498 | 453,490 | 117,492 | 585,146 | 702,638 | 18,567 | 8,546 | 27,113 | 285,491 | 322,635 | 608,126 | |||||||||||||||
Extensions & Improved Recovery | - | - | - | 31,525 | (31,525 | ) | - | - | - | - | 21,796 | (21,796 | ) | - | |||||||||||||
Infill Drilling | - | - | - | - | - | - | - | - | - | 1,325 | (1,325 | ) | - | ||||||||||||||
Technical Revisions | 4,341 | (2,211 | ) | 2,130 | 3,082 | (4,077 | ) | (995 | ) | (1,069 | ) | 378 | (691 | ) | 5,264 | (1,274 | ) | 3,990 | |||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||
Acquisitions | - | - | - | 5,094 | 43,627 | 48,721 | - | - | - | 849 | 7,271 | 8,120 | |||||||||||||||
Dispositions | (280,187 | ) | (137,100 | ) | (417,286 | ) | - | - | - | (11,195 | ) | (5,868 | ) | (17,063 | ) | (106,677 | ) | (51,335 | ) | (158,011 | ) | ||||||
Economic Factors | (1,762 | ) | (926 | ) | (2,688 | ) | (559 | ) | 434 | (124 | ) | (1,230 | ) | (1,113 | ) | (2,343 | ) | (674 | ) | (282 | ) | (957 | ) | ||||
Production | (27,695 | ) | - | (27,695 | ) | (3,787 | ) | - | (3,787 | ) | (1,669 | ) | - | (1,669 | ) | (14,707 | ) | - | (14,707 | ) | |||||||
December 31, 2017 | 6,689 | 1,262 | 7,951 | 152,847 | 593,606 | 746,452 | 3,404 | 1,943 | 5,348 | 192,668 | 253,384 | 446,561 |
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. |
Proved Developed Producing Reserves | Proved Reserves | Total Proved Plus Probable Reserve | |||||
December 31, 2016 | 115,493 | 285,806 | 608,549 | ||||
Extensions & Improved Recovery | 12,919 | 21,796 | - | ||||
Infill Drilling | 246 | 1,325 | - | ||||
Technical Revisions | 2,024 | 5,219 | 3,929 | ||||
Discoveries | - | - | - | ||||
Acquisitions | 85 | 849 | 8,120 | ||||
Dispositions | (82,406 | ) | (106,847 | ) | (158,254 | ) | |
Economic Factors | (348 | ) | (674 | ) | (957 | ) | |
Production | (14,756 | ) | (14,756 | ) | (14,756 | ) | |
December 31, 2017 | 33,257 | 192,718 | 446,632 |
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. |
• | Net reserve changes from drilling activity, improved recovery, technical revisions and economic factors replaced 188 percent and 20 percent of 2017 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. At Lindbergh, net reserve changes replaced 440 percent and 83 percent of 2017 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. At Groundbirch, net reserve changes resulted in 900 percent and -30 percent reserve replacement of 2017 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. The negative reserve replacement percent on the Total Proved Plus Probable Reserves at Groundbirch is a result of economic factors due to lower gas price forecast and the addition of a one percent increase on gas shrinkage. If reserves associated with assets disposed of in 2017 were included in the reserve replacement calculations, reserve replacement would have been -531 percent and -997 percent for Proved Reserves and Total Proved Plus Probable Reserves, respectively. |
• | New reserve additions for development activity during 2017 amounted to 23 MMboe of Proved Reserves. The most significant addition occurred at Lindbergh where Proved Reserves were booked for an area that was previously cyclic steam stimulated. Additional Proved Reserves were also booked at Lindbergh for future infill wells off the pad drilled in 2017 (Pad D04). At Groundbirch, Proved Reserves were booked for section 01-081-21W6 due to offsetting competitor activity. |
• | Technical revisions resulted in a net increase of 5.2 MMboe of Proved Reserves and 3.9 MMboe of Total Proved Plus Probable Reserves. This was primarily due to the re-allocation of drainage area to undeveloped pads. There was also a positive technical revision due to performance at both Lindbergh and Groundbirch. The decrease due to economic factors, predominantly due to gas price reduction, is estimated at 0.7 MMboe for Proved Reserves and 1.0 MMboe for Total Proved Plus Probable Reserves. |
• | Acquisition of a small partner working interest in the Groundbirch area resulted in an increase of 8.1 MMboe of Total Proved Plus Probable Reserves. |
• | Disposition activity in 2017 resulted in a decrease of 106.8 MMboe and 158.3 MMboe of Proved Reserves and Total Proved Plus Probable Reserves, respectively. The properties disposed of were the greater Olds area, the Swan Hills area, W4/W5 properties, Quirk Creek and numerous minor properties. These dispositions resulted in a reduction of 38 percent of Proved Reserves being sold and 26 percent of Total Proved Plus Probable Reserves being sold. Disposition activity had the largest impact on reserve changes for 2017. |
Proved Undeveloped Reserves | ||||||||||||||||
Light Crude Oil and Medium Crude Oil | Heavy Crude Oil | Bitumen | Natural Gas Liquids | Conventional Natural Gas | Shale Gas | Coal Bed Methane | Total Oil Equivalent | |||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | (MMcf) | (Mboe)(2) | |||||||||
First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | |
2015 | 571 | 6,418 | - | 1,512 | - | 82,204 | 448 | 1,277 | 4,730 | 21,512 | 20,825 | 86,662 | - | 6,336 | 5,278 | 110,495 |
2016 | 345 | 5,232 | - | - | 45,978 | 130,007 | 2,920 | 4,760 | 23,826 | 43,240 | - | 86,677 | - | 5,093 | 53,214 | 162,500 |
2017 | 3 | 6 | - | - | 5,053 | 138,600 | 2 | 2 | - | - | 31,525 | 121,493 | - | 258 | 10,312 | 158,900 |
Probable Undeveloped Reserves | ||||||||||||||||
Light Crude Oil and Medium Crude Oil | Heavy Crude Oil | Bitumen | Natural Gas Liquids | Conventional Natural Gas | Shale Gas | Coal Bed Methane | Total Oil Equivalent | |||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | (MMcf) | (Mboe)(2) | |||||||||
First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | First Attributed | Total at year end | |
2015 | 776 | 6,333 | - | 5,374 | 19,185 | 155,201 | 492 | 2,304 | 6,534 | 34,975 | 361,210 | 561,604 | - | 5,544 | 81,744 | 269,565 |
2016 | 581 | 5,245 | - | - | 9,000 | 166,850 | 2,522 | 5,405 | 22,345 | 57,020 | 13,230 | 574,818 | - | 5,039 | 18,032 | 283,646 |
2017 | 1 | 1 | - | - | - | 146,854 | 1 | 1 | - | - | - | 584,005 | - | 1,128 | 2 | 244,378 |
(1) | "First Attributed" refers to reserves first attributed at year end of the corresponding fiscal year. |
(2) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. |
2018 | 2019 | 2020 | Remainder | Total | |
Total Abandonment, Reclamation, Remediation & Dismantling ($millions) | 24 | 31 | 47 | 349 | 451 |
Discounted at ten percent ($millions) | 22 | 25 | 35 | 18 | 101 |
Total | ||||||||
Reserve Category | 2018 | 2019 | 2020 | 2021 | 2022 | Remainder | Undiscounted | Discounted at 10% |
Proved Reserves (Constant Prices and Costs) | 31 | 161 | 139 | 105 | 39 | 1,446 | 1,919 | 719 |
Proved Reserves (Forecast Prices and Costs) | 31 | 163 | 140 | 105 | 39 | 1,455 | 1,932 | 723 |
Proved & Probable Reserves (Forecast Prices and Costs) | 65 | 374 | 618 | 367 | 141 | 3,377 | 4,941 | 2,333 |
Proved Reserves | 2017 | 2016 | 2015 | 2015-20167 Total/Weighted Average | ||||||||||||
Costs Excluding Future Development Costs | ||||||||||||||||
Exploration and Development Capital Expenditures - $MM | 117.4 | 64.2 | 181.8 | 363.4 | ||||||||||||
Exploration and Development Reserve Additions including Revisions - MMboe | 27.7 | 60.7 | (6.1 | ) | 82.3 | |||||||||||
Finding and Development Cost - $/BOE(1) | 4.24 | 1.06 | (29.80 | ) | 4.42 | |||||||||||
Net Acquisition (Disposition) Capital - $MM | (986.7 | ) | (58.9 | ) | (209.6 | ) | (1,255.2 | ) | ||||||||
Net Acquisition (Disposition) Reserve Additions - MMboe | (106.0 | ) | (6.1 | ) | (25.8 | ) | (137.9 | ) | ||||||||
Net Acquisition Cost - $/BOE | 9.31 | 9.66 | 8.12 | 9.10 | ||||||||||||
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM | (869.3 | ) | 5.3 | (27.8 | ) | (891.8 | ) | |||||||||
Reserve Additions including Net Acquisitions (Dispositions) - MMboe | (78.3 | ) | 54.6 | (31.9 | ) | (55.6 | ) | |||||||||
Finding, Development and Acquisition Cost - $/BOE | 11.10 | 0.10 | 0.87 | 16.03 | ||||||||||||
Costs Including Future Development Costs | ||||||||||||||||
Exploration and Development Capital Expenditures - $MM | 117.4 | 64.2 | 181.8 | 363.4 | ||||||||||||
Exploration and Development Change in FDC - $MM | 261.5 | 423.6 | (239.7 | ) | 445.4 | |||||||||||
Exploration and Development Capital including Change in FDC - $MM | 378.8 | 487.8 | (57.9 | ) | 808.7 | |||||||||||
Exploration and Development Reserve Additions including Revisions - MMboe | 27.7 | 60.7 | (6.1 | ) | 82.3 | |||||||||||
Finding and Development Cost - $/BOE | 13.69 | 8.04 | 9.49 | 9.83 | ||||||||||||
Net Acquisition (Disposition) Capital - $MM | (986.7 | ) | (58.9 | ) | (209.6 | ) | (1,255.2 | ) | ||||||||
Net Acquisition (Disposition) FDC - $MM | (309.2 | ) | (40.6 | ) | (107.3 | ) | (457.1 | ) | ||||||||
Net Acquisition (Disposition) Capital including FDC - $MM | (1,295.9 | ) | (99.5 | ) | (316.9 | ) | (1,712.3 | ) | ||||||||
Net Acquisition (Disposition) Reserve Additions - MMboe | (106.0 | ) | (6.1 | ) | (25.8 | ) | (137.9 | ) | ||||||||
Net Acquisition Cost - $/BOE | 12.23 | 16.31 | 12.28 | 12.42 | ||||||||||||
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM | (869.3 | ) | 5.3 | (27.8 | ) | (891.8 | ) | |||||||||
Total Change in FDC - $MM | (47.7 | ) | 383.0 | (347.0 | ) | (11.7 | ) | |||||||||
Total Capital including Change in FDC - $MM | (917.1 | ) | 388.3 | (374.8 | ) | (903.6 | ) | |||||||||
Reserve Additions including Net Acquisitions (Dispositions) - MMboe | (78.3 | ) | 54.6 | (31.9 | ) | (55.6 | ) | |||||||||
Finding, Development and Acquisition Cost including FDC - $/BOE | 11.71 | 7.11 | 11.75 | 16.24 |
Total Proved Plus Probable Reserves | 2017 | 2016 | 2015 | 2015-2017 Total/Weighted Average | ||||||||||||
Costs Excluding Future Development Costs | ||||||||||||||||
Exploration and Development Capital Expenditures - $MM | 117.4 | 64.2 | 181.8 | 363.4 | ||||||||||||
Exploration and Development Reserve Additions including Revisions - MMboe | 3.0 | 76.2 | 73.6 | 152.8 | ||||||||||||
Finding and Development Cost - $/BOE(2) | 39.49 | 0.84 | 2.47 | 2.38 | ||||||||||||
Net Acquisition (Disposition) Capital - $MM | (986.7 | ) | (58.9 | ) | (209.6 | ) | (1,255.2 | ) | ||||||||
Net Acquisition (Disposition) Reserve Additions - MMboe | (150.1 | ) | (15.9 | ) | (35.8 | ) | (201.8 | ) | ||||||||
Net Acquisition Cost - $/BOE | 6.57 | 3.70 | 5.85 | 6.22 | ||||||||||||
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM | (869.3 | ) | 5.3 | (27.8 | ) | (891.8 | ) | |||||||||
Reserve Additions including Net Acquisitions (Dispositions) - MMboe | (147.2 | ) | 60.3 | 37.8 | (49.1 | ) | ||||||||||
Finding, Development and Acquisition Cost - $/BOE(3) | 5.91 | 0.09 | (0.74 | ) | 18.18 | |||||||||||
Costs Including Future Development Costs | ||||||||||||||||
Exploration and Development Capital Expenditures - $MM | 117.4 | 64.2 | 181.8 | 363.4 | ||||||||||||
Exploration and Development Change in FDC - $MM | 163.1 | 193.7 | 341.9 | 698.7 | ||||||||||||
Exploration and Development Capital including Change in FDC - $MM | 280.5 | 257.9 | 523.7 | 1,062.1 | ||||||||||||
Exploration and Development Reserve Additions including Revisions - MMboe | 3.0 | 76.2 | 73.6 | 152.8 | ||||||||||||
Finding and Development Cost - $/BOE(4) | 94.36 | 3.38 | 7.12 | 6.95 | ||||||||||||
Net Acquisition (Disposition) Capital - $MM | (986.7 | ) | (58.9 | ) | (209.6 | ) | (1,255.2 | ) | ||||||||
Net Acquisition (Disposition) FDC - $MM | (455.8 | ) | (124.7 | ) | (133.9 | ) | (714.4 | ) | ||||||||
Net Acquisition (Disposition) Capital including FDC - $MM | (1,442.5 | ) | (183.6 | ) | (343.5 | ) | (1,969.6 | ) | ||||||||
Net Acquisition (Disposition) Reserve Additions - MMboe | (150.1 | ) | (15.9 | ) | (35.8 | ) | (201.8 | ) | ||||||||
Net Acquisition Cost - $/BOE | 9.61 | 11.55 | 9.59 | 9.76 | ||||||||||||
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM | (869.3 | ) | 5.3 | (27.8 | ) | (891.8 | ) | |||||||||
Total Change in FDC - $MM | (292.7 | ) | 69.0 | 208.0 | (15.7 | ) | ||||||||||
Total Capital including Change in FDC - $MM | (1,162.0 | ) | 74.3 | 180.2 | (907.5 | ) | ||||||||||
Reserve Additions including Net Acquisitions (Dispositions) – MMboe | (147.2 | ) | 60.3 | 37.8 | (49.1 | ) | ||||||||||
Finding Development and Acquisition Cost including FDC - $/BOE | 7.90 | 1.23 | 4.77 | 18.50 |
(1) | The negative 2015 F&D Cost excluding FDC for Proved Reserves is due to the negative reserve change including revisions. |
(2) | The high F&D Cost excluding FDC for 2017 P+P Reserves is largely due to the 2017 capital activity focusing on promoting existing Probable Reserves to Proved Reserves combined with minor reserves adds. |
(3) | The negative FD&A Costs excluding FDC for 2015 P+P Reserves are due to the proceeds from dispositions exceeding capital expenditures plus acquisition costs. |
(4) | The high F&D Cost including FDC for 2017 is due to increased estimated FDC. |
2017 | 2016 | 2015 | 2015-2017 Weighted Average(4) | |||||||||
Operating Netback (after risk management), $/BOE(1) | 13.23 | 28.62 | 24.50 | 23.19 | ||||||||
Total Proved Reserves | ||||||||||||
Proved F&D, $/BOE(2) | 13.69 | 8.04 | 9.49 | 9.83 | ||||||||
Proved Recycle Ratio | 0.97 | 3.60 | 2.60 | 2.36 | ||||||||
Total Proved Plus Probable Reserves | ||||||||||||
P+P F&D, $/BOE(2)(3) | 94.36 | 3.38 | 7.12 | 6.95 | ||||||||
P+P Recycle Ratio | 0.14 | 8.50 | 3.40 | 3.34 |
(1) | Operating netback is calculated as shown in "Production History (Netback)". |
(2) | F&D uses Exploration and Development capital including change in FDC divided by Exploration and Development Reserve Additions including Revisions as shown above. |
(3) | The high F&D Cost including FDC for 2017 is due to increased estimated FDC. |
(4) | The three year weighted average is a better indicator of reserve replacement and Recycle Ratio performance given the timing difference between when reserves are booked and when capital is spent to develop them. |
Proved Producing Reserves | Total Proved Reserves | Total Proved Plus Probable Reserves | ||||
RLI, years | 4.0 | 23.0 | 49.0 | |||
Reserves, Mboe(1)(2) | 33.3 | 192.7 | 446.6 | |||
2018 Forecast Production, BOE/d(1) | 22,646 | 22,936 | 24,952 |
(1) | Both reserves and production are Company Interest. |
(2) | Reserves are calculated using Forecast Prices and Costs. |
2017 | 2016 | 2015 | Weighted Average/Total 2015-2017 | ||||||||
Without Net Acquisitions Proved Plus Probable Replacement (%) | 20 | 365 | 282 | 247 | |||||||
P+P Additions plus Revisions, MMboe(1) | 3.0 | 76.2 | 73.6 | 152.8 | |||||||
With Net Acquisitions Proved Plus Probable Replacement (%) | (997 | ) | 289 | 145 | (79 | ) | |||||
P+P Additions, Revisions plus net Acquisitions, MMboe(1) | (147.2 | ) | 60.3 | 37.8 | (49.1 | ) | |||||
Without Net Acquisitions Total Proved Replacement (%) | 187 | 290 | (23 | ) | 133 | ||||||
Total Proved Additions plus Revisions, MMboe(1) | 27.7 | 60.7 | (6.1 | ) | 82.3 | ||||||
With Net Acquisitions Total Proved Replacement (%) | (531 | ) | 261 | (122 | ) | (90 | ) | ||||
Total Proved Additions, Revisions plus net Acquisitions, MMboe(1) | (78.3 | ) | 54.6 | (31.9 | ) | (55.6 | ) | ||||
Current Year Production, MMboe(1) | 14.8 | 20.9 | 26.1 | 61.8 |
(1) | Both reserves and production are Company Interest. |
Producing | Non-Producing | Total | ||||||||
Gross | Net | Gross | Net | Gross | Net | |||||
Crude Oil Wells | ||||||||||
Alberta | 48 | 18 | 79 | 47 | 127 | 65 | ||||
British Columbia | 60 | 33 | 179 | 114 | 239 | 147 | ||||
Saskatchewan | 62 | 2 | 28 | 6 | 90 | 8 | ||||
Bitumen Wells | ||||||||||
Alberta | 30 | 30 | 6 | 1 | 36 | 31 | ||||
Natural Gas Wells | ||||||||||
Alberta | 252 | 93 | 81 | 44 | 333 | 137 | ||||
British Columbia | 122 | 60 | 222 | 126 | 344 | 187 | ||||
Saskatchewan | 1 | 1 | 10 | 2 | 11 | 2 | ||||
Nova Scotia | 19 | 2 | 2 | - | 21 | 2 | ||||
Service Wells(1) | ||||||||||
Alberta | - | - | 132 | 81 | 132 | 81 | ||||
British Columbia | - | - | 183 | 121 | 183 | 121 | ||||
Saskatchewan | - | - | 347 | 24 | 347 | 24 | ||||
Other(2) | ||||||||||
Alberta | - | - | 9 | 7 | 9 | 7 | ||||
British Columbia | - | - | 4 | 4 | 4 | 4 | ||||
Saskatchewan | - | - | - | - | - | - | ||||
Total | 594 | 239 | 1,282 | 577 | 1,876 | 817 |
(1) | Service Wells include disposal, injector, water source and observation wells. |
(2) | Other includes standing, zonally abandoned and suspended wellbores with undefined zones. |
Location | Gross Acres | Net Acres | Maximum Net Acres Expected to Expire During 2018 |
Alberta | 75,325 | 42,703 | 13,400 |
British Columbia | 239,464 | 104,865 | 8,731 |
Nova Scotia | 146,728 | 11,427 | - |
Saskatchewan | 4,404 | 1,932 | - |
Total | 465,921 | 160,927 | 22,131 |
Amount | ||
Nature of Cost | ($million) | |
Acquisition Costs | ||
Proved | 0.1 | |
Unproved | - | |
Exploration Costs(1) | (0.3 | ) |
Development Costs | 117.5 | |
Total | 117.3 |
(1) | Negative due to seismic sales exceeding purchases. |
Development | Exploration | Total | ||||||
Wells | Gross | Net | Gross | Net | Gross | Net | ||
Gas | 5 | 4 | - | - | 5 | 4 | ||
Oil | - | - | - | - | - | - | ||
Bitumen | 12 | 12 | - | - | 12 | 12 | ||
Service/Injection | 10 | 10 | - | - | 10 | 10 | ||
Stratigraphic Test | 2 | 2 | - | - | 2 | 2 | ||
Dry | - | - | - | - | - | - | ||
Total | 29 | 28 | - | - | 29 | 28 |
2018 Estimated Production | |||||||
Constant Prices and Costs | Forecast Prices and Costs | ||||||
Total Proved | Total Probable | Total Proved Plus Probable | Total Proved | Total Probable | Total Proved Plus Probable | ||
Light Crude Oil and Medium Crude Oil (bbl/d) | 821 | 20 | 841 | 821 | 20 | 841 | |
Heavy Crude Oil (bbl/d) | - | - | - | - | - | - | |
Bitumen (bbl/d) | 18,739 | 763 | 19,502 | 18,739 | 763 | 19,502 | |
Conventional Natural Gas (Mcf/d) | 8,700 | 761 | 9,461 | 8,700 | 761 | 9,461 | |
Shale Gas (Mcf/d) | 8,857 | 6,430 | 15,287 | 8,857 | 6,430 | 15,287 | |
Coal Bed Methane (Mcf/d) | 1,243 | 18 | 1,260 | 1,243 | 18 | 1,260 | |
Natural Gas Liquids (bbl/d) | 213 | 31 | 244 | 213 | 31 | 244 | |
Total (BOE/d) | 22,907 | 2,015 | 24,922 | 22,907 | 2,015 | 24,922 |
QUARTER ENDED | YEAR ENDED | ||||||||||||||
Mar 31, 2017 | June 30, 2017 | Sept 30, 2017 | Dec 31, 2017 | Dec 31, 2017 | |||||||||||
Barrels of Oil Equivalent(1) (including realized commodity risk management) | |||||||||||||||
Average Daily Oil Production(2) (BOE/d) | 52,957 | 49,349 | 35,072 | 24,702 | 40,428 | ||||||||||
Produced petroleum revenue ($/BOE) | 34.66 | 32.56 | 28.08 | 37.14 | 32.96 | ||||||||||
Royalties ($/BOE) | (3.30 | ) | (3.56 | ) | (1.89 | ) | (3.52 | ) | (3.10 | ) | |||||
Net operating expenses ($/BOE) | (12.71 | ) | (14.03 | ) | (14.54 | ) | (12.28 | ) | (13.45 | ) | |||||
Transportation costs ($/BOE) | (1.74 | ) | (1.74 | ) | (1.74 | ) | (2.38 | ) | (1.84 | ) | |||||
Realized commodity risk management | (3.48 | ) | (0.07 | ) | 1.15 | (2.90 | ) | (1.34 | ) | ||||||
Operating netback ($/BOE) | 13.43 | 13.16 | 11.06 | 16.06 | 13.23 | ||||||||||
Light Crude Oil (excluding realized commodity risk management) | |||||||||||||||
Average Daily Oil Production(2) (bbl/d) | 10,710 | 9,322 | 5,472 | 2,094 | 6,872 | ||||||||||
Sales price ($/bbl) | 61.73 | 60.36 | 53.24 | 61.25 | 59.52 | ||||||||||
Royalties ($/bbl) | (8.80 | ) | (10.26 | ) | (8.23 | ) | (11.86 | ) | (9.41 | ) | |||||
Net operating expenses ($/bbl) | (15.02 | ) | (14.93 | ) | (16.43 | ) | (20.33 | ) | (15.39 | ) | |||||
Transportation costs ($/bbl) | (1.41 | ) | (1.80 | ) | (1.04 | ) | (1.96 | ) | (1.51 | ) | |||||
Operating netback ($/bbl) | 36.50 | 33.37 | 27.54 | 27.10 | 33.21 | ||||||||||
Bitumen (excluding realized commodity risk management) | |||||||||||||||
Average Daily Bitumen Production(2) (bbl/d) | 14,865 | 13,657 | 12,086 | 14,430 | 13,754 | ||||||||||
Sales price ($/bbl) | 36.78 | 34.20 | 31.57 | 41.28 | 36.17 | ||||||||||
Royalties ($/bbl) | (2.36 | ) | (2.31 | ) | (2.59 | ) | (2.91 | ) | (2.54 | ) | |||||
Net operating expenses ($/bbl) | (11.85 | ) | (12.06 | ) | (14.60 | ) | (10.62 | ) | (12.18 | ) | |||||
Transportation costs ($/bbl) | (2.90 | ) | (2.90 | ) | (2.90 | ) | (2.90 | ) | (2.90 | ) | |||||
Operating netback ($/bbl) | 19.67 | 16.93 | 11.48 | 24.85 | 18.55 | ||||||||||
Natural Gas (excluding realized commodity risk management) | |||||||||||||||
Average Daily Natural Gas Production(2) (Mcf/d) | 121,250 | 118,939 | 83,979 | 42,251 | 91,367 | ||||||||||
Sales price ($/Mcf) | 3.27 | 3.01 | 2.33 | 3.22 | 2.96 | ||||||||||
Royalties ($/Mcf) | 0.19 | 0.14 | 0.38 | (0.01 | ) | 0.19 | |||||||||
Net operating expenses ($/Mcf) | (1.99 | ) | (2.43 | ) | (2.34 | ) | (2.29 | ) | (2.27 | ) | |||||
Transportation costs ($/Mcf) | (0.28 | ) | (0.25 | ) | (0.23 | ) | (0.31 | ) | (0.26 | ) | |||||
Operating netback ($/Mcf) | 1.19 | 0.47 | 0.14 | 0.61 | 0.62 | ||||||||||
NGL (excluding realized commodity risk management) | |||||||||||||||
Average Daily NGL Production(2) (bbl/d) | 7,173 | 6,547 | 3,517 | 11,136 | 4,574 | ||||||||||
Sales price ($/bbl) | 32.22 | 33.40 | 33.07 | 50.71 | 33.96 | ||||||||||
Royalties ($/bbl) | (9.42 | ) | (9.98 | ) | (6.46 | ) | (16.77 | ) | (9.50 | ) | |||||
Net operating expenses ($/bbl) | (13.21 | ) | (15.19 | ) | (13.22 | ) | (9.28 | ) | (13.76 | ) | |||||
Transportation costs ($/bbl | - | - | - | - | - | ||||||||||
Operating netback ($/bbl) | 9.59 | 8.23 | 13.39 | 24.66 | 10.70 |
(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one BOE. |
(2) | Before the deductions of royalties. |
Month Declared | 2017 ($/share) | 2016 ($/share) | 2015 ($/share) | |||
January | - | - | 0.04 | |||
February | - | - | 0.02 | |||
March | - | - | 0.02 | |||
April | - | - | 0.02 | |||
May | - | - | 0.02 | |||
June | - | - | 0.02 | |||
July | - | - | 0.02 | |||
August | - | - | 0.02 | |||
September | - | - | - | |||
October | - | - | - | |||
November | - | - | 0.01 | |||
December | - | - | - | |||
Total | - | - | 0.19 |
• | global energy policy, including the ability of OPEC to set and maintain production levels for oil and non-OPEC member countries' decisions on production levels; |
• | geo-political conditions; |
• | worldwide economic conditions including ongoing credit and liquidity concerns; |
• | weather conditions including weather-related disruptions to the North American natural gas supply; |
• | the supply and price of foreign and North American produced oil and natural gas; |
• | the level of consumer demand; |
• | the price and availability of alternative fuels; |
• | the proximity to, and capacity of, transportation facilities; |
• | the effect of worldwide energy conservation measures; and |
• | government regulation. |
• | historical production from the area compared with production rates from similar producing areas; |
• | the assumed effect of government regulation; |
• | 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 and resources; |
• | marketability of production; and |
• | other government levies that may be imposed over the producing life of reserves. |
• | production falls short of the hedged volumes; |
• | there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the hedge arrangement; |
• | the counterparties to the hedging arrangements or other price risk management contracts fail to perform under those arrangements; or |
• | a sudden unexpected event materially impacts oil and natural gas prices. |
• | will enforce judgments of United States courts obtained in actions against us 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 us or such persons predicated upon the United States federal securities laws or any such state securities or blue sky laws. |
• | 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. |
• | the availability of processing capacity; |
• | the availability and proximity of pipeline capacity; |
• | the availability of storage capacity; |
• | the availability of, and the ability to acquire, water supplies needed for drilling and, hydraulic fracturing, and waterfloods or our ability to dispose of water used or removed from strata at a reasonable cost and in accordance with applicable environmental regulations; |
• | the effects of inclement weather; |
• | the availability of drilling and related equipment; |
• | unexpected cost increases; |
• | accidental events; |
• | currency fluctuations; |
• | changes in regulations; |
• | the availability and productivity of skilled labour; and |
• | the regulation of the oil and natural gas industry by various levels of government and governmental agencies. |
• | the amount and cost of labour to operate the Lindbergh thermal project; |
• | the cost of catalyst and chemicals; |
• | the actual steam oil ratio required to operate the SAGD well pairs; |
• | the cost of natural gas and electricity; |
• | power outages, particularly in winter when freeze-ups could occur; |
• | produced sand causing issues of erosion, hot spots and corrosion; |
• | reliability of the facilities; |
• | the maintenance cost of the facilities; |
• | the cost to transport sales products and the cost to dispose of certain by-products; |
• | the cost of well maintenance and workovers as a result of decreased productivity; |
• | the cost of insurance; and |
• | catastrophic events such as fires, earthquakes, storms or explosions. |
TSX | NYSE | |||||||||||
($) High | ($) Low | Volume | (US$) High | (US$) Low | Volume | |||||||
January | 2.02 | 1.61 | 28,289,089 | 1.50 | 1.24 | 18,993,332 | ||||||
February | 1.79 | 1.53 | 21,336,862 | 1.37 | 1.15 | 16,999,758 | ||||||
March | 1.73 | 1.29 | 42,243,797 | 1.30 | 0.96 | 30,197,020 | ||||||
April | 1.57 | 1.31 | 19,074,863 | 1.18 | 0.96 | 21,148,699 | ||||||
May | 1.44 | 1.05 | 34,321,400 | 1.06 | 0.76 | 23,681,463 | ||||||
June | 1.18 | 0.97 | 22,647,017 | 0.88 | 0.73 | 13,313,892 | ||||||
July | 1.08 | 0.90 | 13,387,887 | 0.82 | 0.71 | 10,357,064 | ||||||
August | 0.93 | 0.68 | 17,135,152 | 0.75 | 0.54 | 12,756,588 | ||||||
September | 1.52 | 0.71 | 58,336,821 | 1.23 | 0.59 | 26,913,140 | ||||||
October | 1.45 | 1.12 | 20,797,271 | 1.12 | 0.91 | 14,073,231 | ||||||
November | 1.52 | 1.00 | 17,718,190 | 1.20 | 0.78 | 14,238,403 | ||||||
December | 1.19 | 0.91 | 19,048,760 | 0.93 | 0.72 | 13,514,433 |
6.25% SERIES B CONVERTIBLE DEBENTURES | ||||||
($) High | ($) Low | Volume | ||||
January | 100.31 | 99.60 | 5,648,000 | |||
February | 100.51 | 99.78 | 1,168,000 | |||
March | 100.11 | 99.79 | 2,901,000 |
Name and Jurisdiction of Residence | Position with Pengrowth | Principal Occupation |
Kelvin B. Johnston(1)(2)(3)(4) Alberta, Canada | Chairman and Director (Director since 2012) | President of Wylander Crude Corp. and Vice President, Corporate Development of Lakeview Energy Inc. |
Derek W. Evans(6) Alberta, Canada | President, Chief Executive Officer and Director (Director since 2009)(5) | President and Chief Executive Officer of Pengrowth. |
Wayne K. Foo(3)(4) Alberta, Canada | Director (Director since 2006)(5) | Chair of the Board of Parex Resources Inc. (energy company) since May 11, 2017; prior thereto, Chief Executive Officer of Parex Resources Inc. since January 2015; prior thereto, President and Chief Executive Officer of Parex Resources Inc. |
James D. McFarland(1)(2) Alberta, Canada | Director (Director since 2010)(5) | Corporate Director since December 31, 2017; prior thereto, President, Chief Executive Officer and Director of Valeura Energy Inc. from June 2010 until October 19, 2017 and Chief Executive Officer and Director thereafter until his retirement on December 31, 2017. |
A. Terence Poole(1) Alberta, Canada | Director (Director since 2005)(5) | Business Consultant and Corporate Director. |
Jamie C. Sokalsky(1)(4) Ontario, Canada | Director (Director since 2015) | Corporate Director since September 2014 and prior thereto, Director, President and Chief Executive Officer of Barrick Gold Corporation. |
D. Michael G. Stewart(2)(3) Alberta, Canada | Director (Director since 2006)(5) | Corporate Director. |
Douglas C. Bowles Alberta, Canada | Vice President and Controller | Vice President and Controller of Pengrowth. |
David M. Granger Alberta, Canada | Vice President, Human Resources | Vice President, Human Resources of Pengrowth since April 2016; prior thereto, Principal, Ener-G HR Consulting Ltd. from April 2014 to March 2016 and prior thereto, Vice President, Human Resources, Brewers Retail Inc. |
Andrew D. Grasby Alberta, Canada | Senior Vice President, General Counsel & Corporate Secretary | Senior Vice President, General Counsel & Corporate Secretary of Pengrowth. |
Randall S. Steele Alberta, Canada | Chief Operating Officer | Chief Operating Officer since January 2018; prior thereto, Senior Vice President, Conventional Operations of Pengrowth since May 2015 and prior thereto, General Manager, Conventional Operations of Pengrowth since 2013. |
Christopher G. Webster Alberta, Canada | Chief Financial Officer | Chief Financial Officer of Pengrowth. |
(1) | Member of the Audit and Risk Committee. |
(2) | Member of Compensation Committee. |
(3) | Member of Corporate Governance and Nominating Committee. |
(4) | Member of Reserves, Health, Safety and Environment Committee. |
(5) | Denotes year first appointed as a director of Pengrowth Corporation, a predecessor of ours. Each of the directors has agreed to serve as such until the next annual meeting of shareholders or until their successor is duly appointed. |
(6) | Prior to January 1, 2016, Mr. Evans was a director of Endurance Energy Ltd. (a private oil and gas company) which filed for protection under the CCAA in May 2016. |
(a) | while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer 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 |
(b) | was subject to 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, after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer. |
Name | Independent | Financially Literate | Relevant Education and Experience |
Kelvin B. Johnston | Yes | Yes | Mr. Johnston is an executive with more than 30 years' experience in the oil and gas industry. Mr. Johnston serves as President of Wylander Crude Corp., a private oil and gas company, a position he has held since July 2006, and as Vice President, Corporate Development of Lakeview Energy Inc., a private oil and gas company, a position held since June 2009. He is currently a managing director of JOG Capital Corp., a provider of private equity to Canadian junior exploration and production companies. Prior positions include serving as President and Chief Executive Officer of Alberta Clipper Energy Inc., Vice-President, Exploration of Thunder Energy Ltd., and various senior technical, executive and board capacities at Husky Oil Ltd., Startech Energy Inc., Impact Energy Inc., Mustang Resources Ltd. and Peerless Energy Inc. Mr. Johnston holds a Bachelor of Science (Hons) degree in Geology from the University of Manitoba and a Masters degree in Economics from the University of Calgary. |
James D. McFarland | Yes | Yes | Mr. McFarland has more than 45 years' experience in the oil and gas industry, most recently as President, Chief Executive Officer, director and co-founder of Valeura Energy Inc., a TSX listed issuer. Prior thereto Mr. McFarland was President, Chief Executive Officer, director and a co-founder of Verenex Energy Inc., a TSX listed issuer. He has served in senior executive roles as Managing Director of Southern Pacific Petroleum N.L. in Australia (an Australian Securities Exchange listed issuer), President and Chief Operating Officer of Husky Oil Limited (a TSX listed issuer) and in a wide range of upstream and corporate functions in an earlier 23-year career with Imperial Oil Limited and other ExxonMobil affiliates in Canada, the US and western Europe. Mr. McFarland currently serves as a director of MEG Energy Corp. and Valeura Energy Inc., and is a past director of Aventura Energy Inc., Vermilion Energy Trust and Vermilion Resources Ltd. (all TSX-listed issuers). Mr. McFarland is a member of the Association of Professional Engineers and Geoscientists of Alberta, the Society of Petroleum Engineers International, the Program Committee of the World Petroleum Council and the Institute of Corporate Directors. He is also a past member of the Australian Institute of Company Directors. Mr. McFarland received a Bachelor of Science in Chemical Engineering from Queen's University and a Master of Science in Petroleum Engineering from the University of Alberta. |
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. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Professional Accountant designation. |
Jamie C. Sokalsky | Yes | Yes | Mr. Sokalsky currently serves as the Chairman of Probe Metals Inc., a TSX-V listed company. He is currently a member of the audit committees of Agnico-Eagle Mines Limited and Royal Gold Inc., both TSX-listed companies. He was formerly President and Chief Executive Officer of Barrick Gold Corporation (2012-2014) and prior to that, Executive Vice President and Chief Financial Officer of Barrick Gold Corporation (1999-2012). He is the former Chairman of Probe Mines Limited. He holds a Bachelor of Commerce degree (honours) from Lakehead University and is a Chartered Professional Accountant. |
2017 ($thousands) | 2016 ($thousands) | |||
Audit Fees | 900 | 884 | ||
Audit Related Fees | - | - | ||
Tax Compliance and Preparation Services | 23 | 8 | ||
Other Tax Services | 23 | 13 | ||
All Other Fees | 105 | 75 | ||
Total | 1,051 | 980 |
• | the issuance of additional Common Shares; |
• | material acquisitions and dispositions of properties; |
• | material capital expenditures; |
• | borrowing; and |
• | the payment of dividends. |
(i) | the Credit Facility; |
(ii) | the Note Purchase Agreement dated October 18, 2012, as amended, concerning the 2012 Senior Notes; and |
(iii) | the Note Purchase Agreement dated May 11, 2010, as amended, concerning the 2010 Senior Notes. |
Bitumen - Reserves Category | ||||||
Total Proved | Total Proved Plus Probable | Total Proved Plus Probable Plus Possible | ||||
Gross Reserves (Mbbl) | 163,334 | 307,057 | 407,028 |
Bitumen - Contingent Resource Category | ||||||
Project Maturity Sub-Class(1) | Low Estimate | Best Estimate | High Estimate | |||
Development Pending(2) - Unrisked (Mbbl) | 17,066 | 35,955 | 59,254 | |||
Chance of Development | 95 | % | 95 | % | 95 | % |
Development Pending - Risked (Mbbl) | 16,212 | 34,157 | 56,291 | |||
Development Unclarified(3) - Unrisked (Mbbl) | - | 66,855 | 95,832 | |||
Chance of Development | - | 58 | % | 58 | % | |
Development Unclarified - Risked (Mbbl) | - | 38,509 | 55,199 |
(1) | Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes. |
(2) | Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development). |
(3) | Development Unclarified describes the status of a project where the evaluation is incomplete and there is ongoing activity to resolve any risks and uncertainties. |
Bitumen - Reserves Category | ||||||
Total Proved | Total Proved Plus Probable | Total Proved Plus Probable Plus Possible | ||||
Net Reserves (Mbbl) | 129,342 | 245,961 | 304,899 |
Bitumen - Contingent Resource Category | ||||||
Project Maturity Sub-Class(1) | Low Estimate | Best Estimate | High Estimate | |||
Development Pending(2) - Unrisked (Mbbl) | 14,097 | 28,051 | 47,711 | |||
Chance of Development | 95 | % | 95 | % | 95 | % |
Development Pending - Risked (Mbbl) | 13,392 | 26,648 | 45,325 | |||
Development Unclarified(3) - Unrisked (Mbbl) | - | 54,572 | 75,509 | |||
Chance of Development | - | 58 | % | 58 | % | |
Development Unclarified - Risked (Mbbl) | - | 31,434 | 43,493 |
(1) | Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes. |
(2) | Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development). |
(3) | Development Unclarified describes the status of a project where the evaluation is incomplete and there is ongoing activity to resolve any risks and uncertainties. |
Before Income Taxes Discounted at (%/year) - $MM | ||||||||||
Reserves Category | 0% | 5% | 10% | 15% | 20% | |||||
Total Proved | 3,375 | 1,779 | 1,112 | 787 | 604 | |||||
Total Proved Plus Probable | 6,437 | 3,219 | 1,764 | 1,045 | 661 | |||||
Total Proved Plus Probable Plus Possible | 9,723 | 4,428 | 2,338 | 1,395 | 913 |
Before Income Taxes Discounted at (%/year) - $MM | |||||||
Project Maturity Sub-Class | 0% | 5% | 10% | 15% | 20% | ||
Development Pending | Low Estimate | Unrisked | 260 | 54 | 11 | 2 | - |
Chance of Development | 95% | 95% | 95% | 95% | 95% | ||
Risked | 247 | 51 | 11 | 2 | - | ||
Best Estimate | Unrisked | 656 | 193 | 58 | 18 | 5 | |
Chance of Development | 95% | 95% | 95% | 95% | 95% | ||
Risked | 623 | 183 | 55 | 17 | 5 | ||
High Estimate | Unrisked | 793 | 499 | 270 | 133 | 57 | |
Chance of Development | 95% | 95% | 95% | 95% | 95% | ||
Risked | 754 | 474 | 256 | 126 | 54 | ||
Development Unclarified | Low Estimate | Unrisked | - | - | - | - | - |
Chance of Development | - | - | - | - | - | ||
Risked | - | - | - | - | - | ||
Best Estimate | Unrisked | 773 | 226 | 35 | (28) | (45) | |
Chance of Development | 58% | 58% | 58% | 58% | 58% | ||
Risked | 445 | 130 | 20 | (16) | (26) | ||
High Estimate | Unrisked | 1,645 | 468 | 119 | 8 | (27) | |
Chance of Development | 58% | 58% | 58% | 58% | 58% | ||
Risked | 947 | 270 | 69 | 5 | (16) |
(1) | An estimate of risked net present value of future net revenue of Contingent Resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation proceeding with the required investment. It includes Contingent Resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized. |
• | Higher evaluation well density – additional drilling within the area of the known accumulation is required to allow further project and reserves definition. |
• | Firm development plans and company commitment for future development phases – confirmation of corporate intent to proceed with defined expansion plans, beyond the initial expansion phase, within an acceptable time period. |
• | Final project design and sanctioning for any potential future expansion phases. |
Bitumen - Contingent Resource Category | ||||||
Project Maturity Sub-Class(1) | Low Estimate | Best Estimate | High Estimate | |||
Development Pending(2) - Unrisked (Mbbl) | 37,090 | 56,088 | 74,632 | |||
Chance of Development | 90 | % | 90 | % | 90 | % |
Development Pending - Risked (Mbbl) | 33,381 | 50,479 | 67,169 |
(1) | Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes. |
(2) | Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development). |
Bitumen - Contingent Resource Category | ||||||
Project Maturity Sub-Class(1) | Low Estimate | Best Estimate | High Estimate | |||
Development Pending(2) - Unrisked (Mbbl) | 32,583 | 46,786 | 60,333 | |||
Chance of Development | 90 | % | 90 | % | 90 | % |
Development Pending - Risked (Mbbl) | 29,324 | 42,108 | 54,300 |
(1) | Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes. |
(2) | Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development). |
Before Income Taxes Discounted at (%/year) - $MM | |||||||
Project Maturity Sub-Class | 0% | 5% | 10% | 15% | 20% | ||
Development Pending | Low Estimate | Unrisked | 456 | 146 | 20 | (34) | (58) |
Chance of Development | 90% | 90% | 90% | 90% | 90% | ||
Risked | 411 | 132 | 18 | (31) | (52) | ||
Best Estimate | Unrisked | 1,109 | 357 | 110 | 14 | (28) | |
Chance of Development | 90% | 90% | 90% | 90% | 90% | ||
Risked | 998 | 321 | 99 | 12 | (25) | ||
High Estimate | Unrisked | 1,897 | 518 | 159 | 36 | (15) | |
Chance of Development | 90% | 90% | 90% | 90% | 90% | ||
Risked | 1,707 | 466 | 143 | 32 | (14) |
(1) | An estimate of risked net present value of future net revenue of Contingent Resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation proceeding with the required investment. It includes Contingent Resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized. |
• | Higher evaluation well density - additional drilling within the area of the known accumulation is required to allow further project and reserves definition. |
• | Regulatory approval of the EPEA application for commercial development is required. |
• | Firm development plans, including high quality capital estimates, and each owner's commitment for future development - confirmation of corporate intent to proceed with defined development plans within an acceptable time period. |
• | Final project design and sanctioning for commercial development. |
Shale Gas - Reserves Category | ||||||
Total Proved | Total Proved Plus Probable | Total Proved Plus Probable Plus Possible | ||||
Gross Reserves (MMcf) | 152,847 | 746,452 | 914,539 |
Shale Gas - Contingent Resource Category | ||||||
Project Maturity Sub-Class(1) | Low Estimate | Best Estimate | High Estimate | |||
Development Pending(2) - Unrisked (MMcf) | 432,886 | 623,895 | 784,231 | |||
Chance of Development | 85 | % | 85 | % | 85 | % |
Development Pending - Risked (MMcf) | 367,953 | 530,311 | 666,597 |
(1) | Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes. |
(2) | Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development). |
Shale Gas - Reserves Category | ||||||
Total Proved | Total Proved Plus Probable | Total Proved Plus Probable Plus Possible | ||||
Net Reserves (MMcf) | 135,786 | 636,588 | 772,456 |
Shale Gas - Contingent Resource Category | ||||||
Project Maturity Sub-Class(1) | Low Estimate | Best Estimate | High Estimate | |||
Development Pending(2) - Unrisked (MMcf) | 432,886 | 623,895 | 784,231 | |||
Chance of Development | 85 | % | 85 | % | 85 | % |
Development Pending - Risked (MMcf) | 367,953 | 530,311 | 666,597 |
(1) | Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes. |
(2) | Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development). |
Before Income Taxes Discounted at (%/year) - $MM | ||||||||||
Reserves Category | 0% | 5% | 10% | 15% | 20% | |||||
Total Proved | 233 | 125 | 70 | 39 | 20 | |||||
Total Proved Plus Probable | 1,564 | 685 | 346 | 187 | 102 | |||||
Total Proved Plus Probable Plus Possible | 2,166 | 860 | 427 | 236 | 135 |
Before Income Taxes Discounted at (%/year) - $MM | |||||||
Project Maturity Sub-Class | 0% | 5% | 10% | 15% | 20% | ||
Development Pending | Low Estimate | Unrisked | 1,023 | 384 | 161 | 71 | 32 |
Chance of Development | 85% | 85% | 85% | 85% | 85% | ||
Risked | 870 | 326 | 137 | 61 | 27 | ||
Best Estimate | Unrisked | 1,892 | 672 | 282 | 128 | 59 | |
Chance of Development | 85% | 85% | 85% | 85% | 85% | ||
Risked | 1,608 | 571 | 240 | 109 | 50 | ||
High Estimate | Unrisked | 2,638 | 887 | 370 | 174 | 87 | |
Chance of Development | 85% | 85% | 85% | 85% | 85% | ||
Risked | 2,242 | 754 | 314 | 148 | 74 |
(1) | An estimate of risked net present value of future net revenue of Contingent Resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation proceeding with the required investment. It includes Contingent Resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized. |
• | A positive commercial environment with respect to prices and capital costs; |
• | The need for long term competitive drilling and completion costs; |
• | Creation and execution of a development plan that will proceed in an acceptable time period which involves an aggressive drilling pace and significant facility expansion; and |
• | Corporate approval and commitment to spend the required capital to develop these Contingent Resources. |
1. | We have evaluated the Corporation's reserves data and contingent resources data as at last day of the reporting issuer's most recently completed financial year. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at last day of the reporting issuer's most recently completed financial year, estimated using forecast prices and costs. The contingent resources data is risked estimates of volume of contingent resources and related risked net present value of future net revenue as at last day of the reporting issuer's most recently completed financial year, estimated using forecast prices and costs. |
2. | The reserves data and contingent resources data are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the reserves data and contingent resources data based on our evaluation. |
3. | We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter). |
4. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data and contingent resources data are free of material misstatement. An evaluation also includes assessing whether the reserves data and contingent resources data are in accordance with principles and definitions presented in the COGE Handbook. |
5. | The following table shows the net present value of 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 Corporation evaluated for the year ended last day of the reporting issuer's most recently completed financial year, and identifies the respective portions thereof that we have evaluated and reported on to the Corporation's management/board of directors: |
Independent Qualified Reserves Evaluator or Auditor | Effective Date of Evaluation Report | Location of Reserves (Country or Foreign Geographic Area) | Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - $M) | |||
Audited | Evaluated | Reviewed | Total | |||
GLJ Petroleum Consultants | December 31, 2017 | Canada | - | 2,170,276 | - | 2,170,276 |
6. | The following tables set forth the risked volume and risked net present value of future net revenue (before deduction of income taxes) attributed to best estimate contingent resources, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the Corporation's statement prepared in accordance with Form 51-101F1 and identifies the respective portions of the contingent resources data that we have evaluated and reported on to the Corporation's management/board of directors: |
Classification | Independent Qualified Reserves Evaluator or Auditor | Effective Date of Evaluation Report | Location of Resources Other than Reserves (Country or Foreign Geographic Area) | Risked Volume (MMboe) | Risked Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - $M) | ||
Audited | Evaluated | Total | |||||
Development Pending Contingent Resources (2C) | GLJ Petroleum Consultants | December 31, 2017 | Canada | 192.0 | - | 393,625 | 393,625 |
Classification | Independent Qualified Reserves Evaluator or Auditor | Effective Date of Evaluation Report | Location of Resources Other than Reserves (Country or Foreign Geographic Area) | Risked Volume (MMboe) | |
Development Unclarified Contingent Resources | GLJ Petroleum Consultants | December 31, 2017 | Canada | 38.5 |
7. | In our opinion, the reserves data and contingent resources data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data and contingent resources data that we reviewed but did not audit or evaluate. |
8. | We have no responsibility to update our reports referred to in paragraphs 5 and 6 for events and circumstances occurring after the effective date of our reports. |
9. | Because the reserves data and contingent resources data are based on judgements regarding future events, actual results will vary and the variations may be material. |
(signed) "Todd J. Ikeda" |
Todd J. Ikeda, P.Eng. |
Vice President |
(a) | reviewed the Corporation'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 and the contingent resources 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 contingent resources 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, contingent resources data, or prospective resources data; and |
(c) | the content and filing of this report. |
(signed) "Derek W. Evans" | (signed) "Randall S. Steele" | |
Derek W. Evans | Randall S. Steele | |
President and Chief Executive Officer | Chief Operating Officer | |
(signed) "Wayne K. Foo" | (signed) "Kelvin B. Johnston" | |
Wayne K. Foo | Kelvin B. Johnston | |
Director | Chairman of the Board | |
February 28, 2018 |
![]() | PENGROWTH ENERGY CORPORATION Policies and Practices | Page 1 of 11 |
TERMS OF REFERENCE AUDIT AND RISK COMMITTEE |
• | 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; |
• | provide an avenue of communication among the external auditors, the internal auditors, management and the Board; and |
• | oversee Pengrowth’s risk management processes. |
1. | Review and reassess the adequacy of the Committee's terms of reference at least annually, submit the terms of reference to the Board for approval and have the document published annually in Pengrowth's annual information circular and 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 financial 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 information 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 matters required to be communicated to the Committee by the external auditors in accordance with generally accepted auditing standards. |
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 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 NI 52-110. If proxies are solicited for the election of directors of Pengrowth, the 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 Committee shall advise the external auditors of their accountability to the Committee and the Board as representatives of Pengrowth’s shareholders to whom the external auditors are ultimately responsible. The external auditors shall report directly to the Committee. The 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 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. |
2. | Approve the fees and other compensation to be paid to the external auditors. |
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. |
1. | 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. |
2. | 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. |
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. |
4. | Conduct an annual performance evaluation of the Committee. |
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 Chairman of the Board and the President and CEO. |
1. | On an annual basis, the Committee should review and discuss with the external auditors all significant relationships they have with Pengrowth that could impair the auditors' independence. |
2. | The 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 52 108 Auditor 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. |
7. | Monitor compliance with the lead auditor rotation requirements of Regulation S-X. |
(a) | The risks inherent in the Corporation’s businesses, facilities, strategic direction; |
(b) | The overall risk management strategies (including insurance coverage); |
(c) | The risk retention philosophy and the resulting uninsured exposure of the Corporation; and |
(d) | The loss prevention policies, risk management and hedging programs, and standard and accountabilities of the Corporation in the context of competitive and operational considerations. |
1. | On at least an annual basis, review with Pengrowth's legal 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. |
2. | Annually prepare a report to shareholders as required by the United States' Securities and Exchange Commission; the report should be included in Pengrowth's annual information circular. |
3. | Ensure due compliance with each obligation to certify, on an annual and interim basis, internal control over financial reporting and disclosure controls and procedures in accordance with applicable securities laws and regulations. |
4. | Review all exceptions to established policies, procedures and internal controls of Pengrowth, which have been approved by any two officers of Pengrowth. |
5. | Perform any other activities consistent with this Charter, Pengrowth's by-laws, and other governing law as the Committee or the Board deems necessary or appropriate. |
6. | Maintain minutes of meetings and periodically report to the Board on significant results of the foregoing activities. |
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 Pengrowth during any 12 month period within the last three years. |
4. | 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 amounts of compensation (including deferred compensation) for prior service with that firm if the compensation is not contingent in any way on continued service. |
5. | For the purposes of paragraph 3(f), direct compensation does not include |
(a) | remuneration for acting as a member of the Board or of any committee of the Board, 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. |
6. | 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 committee of the Board on a part-time basis. |
7. | For the purpose of paragraph 3, "Pengrowth" includes all of its subsidiary entities. |
8. | Despite any determination made under paragraphs 3 through 7 above, an individual who |
(a) | accepts, directly or indirectly, any consulting, advisory or other compensatory fee from Pengrowth or any subsidiary entity of 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, |
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 or any subsidiary entity of 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. |
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: |
i. | The term affiliate of, or a person affiliated with, 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. |
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. |
iii. | The following will be deemed to be affiliates: |
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. |
(a) | (i) 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). |
(ii) | In addition, in affirmatively determining the independence of any director who will serve on the compensation committee of the listed company's board of directors, the board of directors must consider all factors specifically relevant to determining whether a director has a relationship to the listed company which is material to that director's ability to be independent from management in connection with the duties of a compensation committee member, including, but not limited to: |
(A) | the source of compensation of such director, including any consulting, advisory or other compensatory fee paid by the listed company to such director; and |
(B) | whether such director is affiliated with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. |
(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 $120,000 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 is a current partner or employee of a firm that is the listed company's internal or external auditor; (B) the director has an immediate family member who is a current partner of such a firm; (C) the director has an immediate family member who is a current employee of such a firm and personally works on the listed company's audit; or (D) the director or an immediate family member was within the last three years 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 $1 million, or 2% of such other company's consolidated gross revenues. |
PENGROWTH 2017 Management's Discussion and Analysis | 1 |
PENGROWTH 2017 Management's Discussion and Analysis | 2 |
PENGROWTH 2017 Management's Discussion and Analysis | 3 |
– | trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion ("EBITDA"), other items and EBITDA related to material divestments ("Adjusted EBITDA"); |
– | trailing twelve months interest expense excluding interest expense related to debt repaid with proceeds from divestments ("Adjusted Interest Expense"); |
– | Adjusted EBITDA to Adjusted Interest Expense ratio (the "Interest Coverage" ratio); |
– | Debt before working capital to the trailing twelve months Adjusted EBITDA; and |
– | Total debt before working capital as a percentage of total book capitalization ("Debt to Book Capitalization"). |
PENGROWTH 2017 Management's Discussion and Analysis | 4 |
PENGROWTH 2017 Management's Discussion and Analysis | 5 |
2017 Actual | 2017 Guidance (1) | |||
Production (boe/d) | 40,428 | 39,500 - 41,500 | ||
Capital expenditures ($ millions) | 117.9 | 125 | ||
Funds flow from operations ($ millions) | 69.4 | 65 | ||
Royalty expenses (% of produced petroleum revenue) (2) (3) | 9.4 | 9.0 | ||
Net operating expenses ($/boe) (2) | 13.45 | 13.00 - 13.50 | ||
Cash G&A expenses ($/boe) (2) | 3.84 | 3.50 - 4.00 |
(1) | Per boe estimates based on high and low ends of production Guidance. |
(2) | See definition under section "Non-GAAP Financial Measures". |
(3) | Excludes financial commodity risk management activities. |
2018 Guidance (1) | ||
Production (boe/d) | 22,500 - 23,500 | |
Capital expenditures ($ millions) | 65 | |
Royalty expenses (% of produced petroleum revenue) (2) (3) | 6.0 | |
Net operating expenses ($/boe) (2) | 10.50 - 11.50 | |
Cash G&A expenses ($/boe) (2) | 3.10 - 3.35 |
(1) | Per boe estimates based on high and low ends of production Guidance. |
(2) | See definition under section "Non-GAAP Financial Measures". |
(3) | Excludes financial commodity risk management activities. |
PENGROWTH 2017 Management's Discussion and Analysis | 6 |
Three months ended | Twelve months ended | |||||||
($ millions except per boe amounts) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Total debt before working capital (1) | 610.5 | 1,687.3 | 610.5 | 1,687.3 | ||||
Production (boe/d) | 24,702 | 54,354 | 40,428 | 57,058 | ||||
Capital expenditures | 28.2 | 28.4 | 117.9 | 64.4 | ||||
Funds flow from operations (2) (3) | 13.5 | 111.7 | 69.4 | 429.7 | ||||
Operating netback before realized commodity risk management ($/boe) (4) | 18.96 | 15.16 | 14.57 | 10.15 | ||||
Adjusted net income (loss) (4) (5) | (217.1 | ) | 45.3 | (745.6 | ) | 48.0 | ||
Net income (loss) (5) | (210.4 | ) | (92.4 | ) | (683.8 | ) | (293.7 | ) |
(1) | Includes Credit Facilities, current and long term portions of term notes and convertible debentures, as applicable. Excludes letters of credit and finance leases. |
(2) | Funds flow from operations for the twelve months ended December 31, 2017 includes a $12.7 million loss related to the early settlement of commodity risk management contracts. |
(3) | Funds flow from operations for the three and twelve months ended December 31, 2017 exclude $34.8 million and $37.6 million, respectively, of losses from the settlement of foreign exchange swap contracts related to the prepayment of term notes as this was considered a financing activity. |
(4) | See definition under section "Non-GAAP Financial Measures". |
(5) | Three and twelve months ended December 31, 2017 include impairment charges of $130.0 million ($95 million after-tax) and $634.4 million ($463 million after-tax), respectively, primarily related to 2017 property dispositions. |
• | Total debt before working capital was reduced by Cdn$1,076.8 million during 2017 primarily through the prepayment of the U.S.$400 million 6.35 percent term notes, U.S.$265 million 6.98 percent notes, Cdn$15 million 6.61 percent notes, prepayments of Cdn$115.4 million of principal during the fourth quarter on the remaining outstanding term notes, and the repayment of Cdn$126.6 million of convertible debentures at maturity. |
• | Formalized an agreement with bank syndicate and noteholders removing and relaxing certain financial covenants through September 30, 2019. |
• | In the first quarter, Pengrowth closed the sale of a 4.0 percent gross overriding royalty ("GORR") interest on the Lindbergh property and certain seismic assets for proceeds of $250 million. A pre-tax gain on disposition of $144.7 million, net of transaction costs, was recorded. |
• | In the second quarter, Pengrowth sold its non-producing Montney lands at Bernadet in north east British Columbia for cash consideration of $92 million. A pre-tax loss on disposition of $33.4 million was recorded. |
• | In the third quarter, the Judy Creek assets were sold for total consideration of $185 million, before customary adjustments. A $71.0 million pre-tax PP&E impairment was recorded related to this transaction. Pengrowth also sold its Olds/Garrington assets for cash consideration of $300 million, before customary adjustments. A $306.3 million pre-tax PP&E impairment was recorded related to this transaction. |
• | In the fourth quarter, Pengrowth sold its remaining Swan Hills assets in north central Alberta for total consideration of $150 million, subject to customary adjustments, resulting in a pre-tax loss on disposition of $169.0 million. Pengrowth also closed the sale of the vast majority of its remaining non-core legacy assets in Alberta for nominal cash consideration and the assumption of abandonment and reclamation liabilities by the purchaser. A $56.1 million pre-tax PP&E impairment was recorded related to this transaction. |
• | Funds flow from operations was $69.4 million in 2017, net of restructuring related severance costs of $10.5 million. |
• | Additional expense reductions were accomplished with 2017 net operating expenses and cash G&A expenses decreasing $77.0 million and $13.8 million, respectively, compared to 2016. |
• | 10 producer, 10 injector, 2 infill and 2 observation wells were drilled at the Lindbergh thermal project in 2017. |
• | 4 wells were drilled as part of the drilling and optimization program at Groundbirch in 2017. The wells will be completed in early 2018. |
PENGROWTH 2017 Management's Discussion and Analysis | 7 |
($ millions) | Q4/16 vs. Q4/17 | % Change | 2016 vs. 2017 | % Change | |||||||
Funds flow from operations for comparative period | Q4/16 | 111.7 | 2016 | 429.7 | |||||||
Increase (decrease) due to: | |||||||||||
Volumes | (91.3 | ) | (82 | ) | (170.5 | ) | (40 | ) | |||
Prices including differentials | 7.6 | 7 | 96.0 | 22 | |||||||
Realized commodity risk management | (83.8 | ) | (75 | ) | (405.5 | ) | (94 | ) | |||
Royalties | 6.1 | 5 | (5.8 | ) | (1 | ) | |||||
Expenses: | |||||||||||
Net operating | 42.1 | 38 | 77.0 | 18 | |||||||
Cash G&A | 5.2 | 5 | 13.8 | 3 | |||||||
Interest & financing | 13.9 | 12 | 34.8 | 8 | |||||||
Restructuring costs - severance | (1.3 | ) | (1 | ) | (10.5 | ) | (2 | ) | |||
Other - including transportation | 3.3 | 3 | 10.4 | 2 | |||||||
Net change | (98.2 | ) | (88 | ) | (360.3 | ) | (84 | ) | |||
Funds flow from operations (1) (2) | Q4/17 | 13.5 | 2017 | 69.4 |
(1) | Funds flow from operations for the twelve months ended December 31, 2017 includes a $12.7 million loss related to the early settlement of commodity risk management contracts. |
(2) | Funds flow from operations for the three months and twelve months ended December 31, 2017 exclude $34.8 million and $37.6 million, respectively, of losses from the settlement of foreign exchange swap contracts related to the prepayment of term notes as this was considered a financing activity. |
PENGROWTH 2017 Management's Discussion and Analysis | 8 |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Net income (loss) | (210.4 | ) | (92.4 | ) | (683.8 | ) | (293.7 | ) |
Exclude non-cash items from net income (loss): | ||||||||
Change in fair value of commodity and power risk management contracts | (33.3 | ) | (104.4 | ) | 14.2 | (422.8 | ) | |
Unrealized foreign exchange gain (loss) (1) | 31.0 | (61.6 | ) | 51.4 | (33.4 | ) | ||
Tax effect on non-cash items above | 9.0 | 28.3 | (3.8 | ) | 114.5 | |||
Total excluded | 6.7 | (137.7 | ) | 61.8 | (341.7 | ) | ||
Adjusted net income (loss) (2) | (217.1 | ) | 45.3 | (745.6 | ) | 48.0 |
(1) | Relates to the foreign denominated debt net of associated foreign exchange risk management contracts. |
(2) | See definition under section "Non-GAAP Financial Measures". |
The following table represents a continuity of adjusted net income (loss): | |||||||
($ millions) | Q4/16 vs. Q4/17 | 2016 vs. 2017 | |||||
Adjusted net income (loss) for comparative period | Q4/16 | 45.3 | 2016 | 48.0 | |||
Funds flow from operations increase (decrease) | (98.2 | ) | (360.3 | ) | |||
DD&A and accretion expense (increase) decrease | 45.7 | 146.0 | |||||
Impairment charges (increase) decrease | (130.0 | ) | (634.4 | ) | |||
Realized foreign exchange gain (loss) on settled FX swaps | (81.8 | ) | (84.6 | ) | |||
Loss on property dispositions (increase) decrease | (9.0 | ) | (35.5 | ) | |||
Restructuring costs - onerous office lease contracts | (18.5 | ) | (26.5 | ) | |||
Loss on extinguishment of debt | (49.2 | ) | (56.7 | ) | |||
Other | 11.6 | 9.7 | |||||
Estimated tax on above | 67.0 | 248.7 | |||||
Net change | (262.4 | ) | (793.6 | ) | |||
Adjusted net income (loss) (1) | Q4/17 | (217.1 | ) | 2017 | (745.6 | ) |
(1) | See definition under section "Non-GAAP Financial Measures". |
PENGROWTH 2017 Management's Discussion and Analysis | 9 |
Estimated Impact on 12 Month Funds Flow | |||||||||
COMMODITY PRICE ENVIRONMENT (1) | Assumption | Change | (Cdn$ millions) | ||||||
West Texas Intermediate Oil (2) | U.S.$/bbl | $62.91 | $1.00 | ||||||
Bitumen | 7.3 | ||||||||
Oil risk management (3) | (4.5 | ) | |||||||
Light oil and NGLs | 0.5 | ||||||||
Net impact of U.S.$1/bbl increase in WTI | 3.3 | ||||||||
Oil differentials (2) | |||||||||
Bitumen | U.S.$/bbl | $27.13 | $1.00 | (7.3 | ) | ||||
Light oil | U.S.$/bbl | $3.12 | $1.00 | (0.4 | ) | ||||
Physical oil differential risk management (4) | 7.7 | ||||||||
Net impact of U.S.$1/bbl increase in differentials | — | ||||||||
AECO Natural Gas (2) | Cdn$/Mcf | $1.20 | $0.10 | ||||||
Natural gas | 0.9 | ||||||||
Net impact of Cdn$0.10/Mcf increase in AECO | 0.9 |
(1) | Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time. The exchange rate of Cdn$1 = U.S.$0.81 was used for the 12 month period. |
(2) | Commodity price is based on an estimation of the 12 month forward price curve at February 2, 2018 and does not include the impact of commodity risk management contracts. |
(3) | Includes commodity risk management contracts as at February 2, 2018. |
(4) | Reflects 2018 physical delivery contracts for 17,000 bbl/d of diluted bitumen at a fixed price differential of approximately U.S.$16.82/bbl. See Commodity Prices section of this MD&A for more information. |
• | The prepayment of all of the term notes due August 21, 2018 (U.S.$265 million and Cdn$15 million) and additional prepayments of Cdn$115.4 million of principal during the fourth quarter on the remaining outstanding term notes. |
• | Amendments to the existing financial covenants effective for the quarter ending September 30, 2017 through to and including the quarter ending September 30, 2019 in the case of its term notes, and expiring on March 31, 2019 in the case of its Credit Facility (the "Waiver Period"). During the Waiver Period: |
◦ | The Debt to Adjusted EBITDA ratio covenant and the Debt to Book Capitalization ratio covenant do not apply. |
◦ | The trailing 12 month Adjusted EBITDA to Adjusted Interest Expense minimum ratio covenant is revised as follows: |
Year | Q1 | Q2 | Q3 | Q4 |
2017 | n/a | n/a | 4.0 times | 0.77 times |
2018 | 0.75 times | 0.68 times | 1.03 times | 1.01 times |
2019 | 1.13 times | 1.19 times | 1.23 times | 4.0 times |
PENGROWTH 2017 Management's Discussion and Analysis | 10 |
• | The Lenders were granted security over Pengrowth’s assets, similar to other oil and gas borrowing base loans. |
• | The remaining outstanding term notes maturing in 2019 through 2024 are subject to a two percentage point increase in interest rates (which increases to three percentage points on January 1, 2020). A one-time amendment fee of 0.5 percent on outstanding term notes was also paid to the holders of term notes due after 2018. |
• | The aggregate credit limit under the Credit Facility was reduced to $330 million following the closing of the Swan Hills asset sale, the $50 million Demand Credit Facility was eliminated and interest rates under the Credit Facility increased by 2 percentage points. A one time amendment fee of 0.5 percent of the aggregate credit limit was paid to the syndicate members of the Credit Facility. |
• | The 2017 debt restructuring was a substantial modification of terms and was therefore reflected as an extinguishment of debt for accounting purposes with a Loss on extinguishment of debt reflected in the 2017 Consolidated Statement of Income (Loss) in the amount of $56.7 million composed of $55.2 million of debt restructuring costs and $1.5 million of remaining unamortized issue costs. Debt restructuring costs comprised the amendment fees, make whole payments on the principal prepayments, as well as professional fees. |
PENGROWTH 2017 Management's Discussion and Analysis | 11 |
Twelve month trailing actual covenant (1): | ||
Interest Coverage ratio at December 31, 2017 | 1.6 | |
Minimum Interest Coverage compliance ratio required at December 31, 2017 | 0.77 | |
Twelve month trailing Adjusted Interest Expense ($ millions): | Dec 31, 2017 | |
Interest and financing charges | 70.7 | |
Less fees and interest on debt repaid with asset divestment proceeds (1) | (34.3 | ) |
Adjusted Interest Expense | 36.4 | |
Twelve month trailing Adjusted EBITDA ($ millions): | ||
Net income (loss) | (683.8 | ) |
Add (deduct): | ||
Interest and financing charges | 70.7 | |
Deferred income tax expense (recovery) | (223.8 | ) |
Depletion, depreciation, amortization and accretion | 219.0 | |
Impairment | 634.4 | |
(Gain) loss on disposition of properties | 62.6 | |
Other items (2) | 67.8 | |
EBITDA related to material dispositions (2) | (88.9 | ) |
Adjusted EBITDA | 58.0 |
(1) | Calculation of the financial covenant is based on specific definitions within the agreements and contains adjustments, pursuant to the agreements, some of which cannot be readily replicated by referring to Pengrowth’s Consolidated Financial Statements. |
(2) | Includes the impact of changes in fair value of commodity risk management contracts, unrealized foreign exchange on long term debt, and other adjustments pursuant to the actual covenant calculations, including certain allocated G&A expenses. |
(Cdn$ millions) | December 31, 2016 vs. December 31, 2017 | |
Total debt before working capital at December 31, 2016 (1) | 1,687.3 | |
Increase (decrease) due to: | ||
Foreign exchange impact of the stronger Canadian dollar on U.S. denominated debt | (65.7 | ) |
Foreign exchange impact of the weaker Canadian dollar on U.K. denominated debt | 0.6 | |
Credit facilities and bank indebtedness increase | 109.0 | |
Term notes repayment | (996.0 | ) |
Convertible debenture repayment | (126.6 | ) |
Issue cost amortization | 1.9 | |
Total increase (decrease) | (1,076.8 | ) |
Total debt before working capital at December 31, 2017 (1) | 610.5 |
(1) | Includes Credit Facilities, current and long term portions of term notes and convertible debentures, as applicable. |
PENGROWTH 2017 Management's Discussion and Analysis | 12 |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Drilling, completions and facilities | ||||||||
Lindbergh (1) | 12.1 | 12.1 | 79.5 | 21.2 | ||||
Groundbirch and conventional assets | 15.4 | 1.4 | 22.0 | 4.1 | ||||
Total drilling, completions and facilities | 27.5 | 13.5 | 101.5 | 25.3 | ||||
Land & seismic acquisitions (2) | 0.2 | 0.9 | 0.4 | (0.2 | ) | |||
Maintenance capital | 0.4 | 14.1 | 15.3 | 38.6 | ||||
Development capital | 28.1 | 28.5 | 117.2 | 63.7 | ||||
Other capital | 0.1 | (0.1 | ) | 0.7 | 0.7 | |||
Capital expenditures | 28.2 | 28.4 | 117.9 | 64.4 |
(1) | Excludes capitalized interest, see Interest and Financing Charges section of the MD&A. |
(2) | Seismic acquisitions are net of seismic sales revenue. |
PENGROWTH 2017 Management's Discussion and Analysis | 13 |
Reserves Summary (1) (MMboe except as noted) | 2017 | 2016 | |||
Proved Reserves | |||||
Additions + revisions for the year | 27.7 | 60.7 | |||
Net dispositions for the year | (106.0 | ) | (6.1 | ) | |
Total proved reserves at period end | 192.7 | 285.8 | |||
Proved reserve future development costs ($ millions) | 1,932 | 1,980 | |||
Proved plus Probable Reserves (P+P) | |||||
Additions + revisions for the year | 3.0 | 76.2 | |||
Net dispositions for the year | (150.1 | ) | (15.9 | ) | |
Total proved plus probable reserves at period end | 446.6 | 608.5 | |||
P+P reserve future development costs ($ millions) | 4,941 | 5,234 | |||
Total production (MMboe) | 14.8 | 20.9 |
(1) | Based on January 1, 2018 GLJ pricing and prepared in accordance with NI 51-101. |
Three months ended | Twelve months ended | |||||||||||
Daily production | Dec 31, 2017 | % of total | Dec 31, 2016 | % of total | Dec 31, 2017 | % of total | Dec 31, 2016 | % of total | ||||
Light oil (bbl/d) | 2,094 | 8 | 10,597 | 19 | 6,872 | 17 | 11,736 | 21 | ||||
Bitumen (bbl/d) | 14,430 | 58 | 15,209 | 28 | 13,754 | 34 | 15,585 | 27 | ||||
Natural gas liquids (bbl/d) | 1,136 | 5 | 7,976 | 15 | 4,574 | 11 | 7,763 | 14 | ||||
Natural gas (Mcf/d) | 42,251 | 29 | 123,434 | 38 | 91,367 | 38 | 131,847 | 38 | ||||
Total boe/d | 24,702 | 54,354 | 40,428 | 57,058 |
PENGROWTH 2017 Management's Discussion and Analysis | 14 |
Three months ended | Twelve months ended | |||||||
(U.S.$/bbl) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Average exchange rate (Cdn$1 = U.S.$) | 0.79 | 0.75 | 0.77 | 0.75 | ||||
Average Benchmark Prices | ||||||||
WTI oil | 55.39 | 49.33 | 50.93 | 43.37 | ||||
WCS differential to WTI | (12.28 | ) | (14.33 | ) | (11.96 | ) | (13.84 | ) |
WCS oil | 43.11 | 35.00 | 38.97 | 29.53 |
Three months ended | Twelve months ended | |||||||
(Cdn$/bbl) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Average Benchmark Prices | ||||||||
WTI oil | 70.45 | 65.78 | 66.09 | 57.32 | ||||
Edmonton par light oil | 68.98 | 61.62 | 62.90 | 53.05 | ||||
WCS oil | 54.83 | 46.67 | 50.53 | 38.96 | ||||
Differentials to WTI | ||||||||
Edmonton par | (1.47 | ) | (4.16 | ) | (3.19 | ) | (4.27 | ) |
WCS oil | (15.62 | ) | (19.11 | ) | (15.56 | ) | (18.36 | ) |
Average Sales Prices | ||||||||
Light oil | 61.25 | 59.59 | 59.52 | 50.24 | ||||
Bitumen (1) (2) | 41.28 | 37.88 | 36.17 | 30.19 | ||||
Natural gas liquids | 50.71 | 30.80 | 33.96 | 22.60 |
(1) | Fourth quarter and full year 2017 bitumen average sale prices were lower by approximately Cdn$4.86/bbl and Cdn$5.72/bbl, respectively, due to the impact of physical delivery contracts. |
(2) | Calculated based on bitumen sales volumes and excludes diluent. |
PENGROWTH 2017 Management's Discussion and Analysis | 15 |
Three months ended | Twelve months ended | |||||||
(Cdn$) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Average Benchmark Prices | ||||||||
NYMEX gas (per MMBtu) | 3.71 | 4.24 | 3.92 | 3.38 | ||||
AECO monthly gas (per MMBtu) | 1.98 | 2.81 | 2.43 | 2.09 | ||||
Differential to NYMEX | ||||||||
AECO differential (per MMBtu) | (1.73 | ) | (1.43 | ) | (1.49 | ) | (1.29 | ) |
Average Sales Price | ||||||||
Natural gas (per Mcf) (1) | 3.22 | 3.03 | 2.96 | 2.25 |
(1) | Average sales prices are recorded in Mcf to reflect the volumetric reporting standard for Pengrowth's natural gas. |
PENGROWTH 2017 Management's Discussion and Analysis | 16 |
Three months ended | Twelve months ended | |||||||
($/boe) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Produced petroleum revenue (1) | 37.14 | 33.62 | 32.96 | 26.86 | ||||
Realized commodity risk management gain (loss) | (2.90 | ) | 15.44 | (1.34 | ) | 18.47 | ||
Total including realized commodity risk management | 34.24 | 49.06 | 31.62 | 45.33 |
(1) | Calculated based on light oil, bitumen, natural gas liquids and natural gas sales volumes and excludes processing income, diluent and other revenue. See definition under section "Non-GAAP Financial Measures". |
Three months ended | Twelve months ended | |||||||
($ millions except per unit amounts) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Oil risk management gain (loss) | (9.0 | ) | 47.3 | (25.8 | ) | 289.2 | ||
$/bbl (1) | (5.92 | ) | 19.92 | (3.43 | ) | 28.92 | ||
Natural gas risk management gain (loss) | 2.4 | 29.9 | 6.0 | 96.5 | ||||
$/Mcf | 0.62 | 2.63 | 0.18 | 2.00 | ||||
Total realized commodity risk management gain (loss) | (6.6 | ) | 77.2 | (19.8 | ) | 385.7 | ||
$/boe | (2.90 | ) | 15.44 | (1.34 | ) | 18.47 |
(1) | Includes light oil and bitumen. |
PENGROWTH 2017 Management's Discussion and Analysis | 17 |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Fair value of commodity risk management assets (liabilities) at period end | (39.8 | ) | (54.0 | ) | (39.8 | ) | (54.0 | ) |
Less: Fair value of commodity risk management assets (liabilities) at beginning of period | (6.5 | ) | 51.1 | (54.0 | ) | 370.5 | ||
Change in fair value of commodity risk management contracts for the period | (33.3 | ) | (105.1 | ) | 14.2 | (424.5 | ) |
Crude Oil | |||
Financial Swap Contracts | |||
Reference point | Term | Volume (bbl/d) | Price/bbl (U.S.$) |
WTI | 2018 | 8,000 | 49.97 |
Collars | Price/bbl (U.S.$) | |||
Reference point | Term | Volume (bbl/d) | Bought Puts | Sold Calls |
WTI | 2018 | 2,000 | $48.00 | $53.48 |
PENGROWTH 2017 Management's Discussion and Analysis | 18 |
WCS Differentials | |||
Physical Delivery Contracts | |||
Reference point | Term | Volume of diluted bitumen (bbl/d) | Price/bbl (U.S.$) |
Western Canada Select | 2018 | 12,000 | WTI less $16.95 |
Western Canada Select | 2018 | 5,000 | WTI less $16.50 - $19.25 |
Western Canada Select | 2019 | 2,500 | WTI less $17.95 |
Western Canada Select | 2019 | 5,000 | WTI less $17.70 - $20.45 |
($ millions) | ||||
Crude oil swaps and collars | Cdn$1/bbl increase in future oil prices | Cdn$1/bbl decrease in future oil prices | ||
Increase (decrease) to fair value of oil risk management contracts | (3.5 | ) | 3.5 |
PENGROWTH 2017 Management's Discussion and Analysis | 19 |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Light oil | 11.8 | 58.1 | 149.3 | 215.8 | ||||
Bitumen | 54.8 | 53.0 | 181.6 | 172.2 | ||||
Natural gas liquids | 5.3 | 22.6 | 56.7 | 64.2 | ||||
Natural gas | 12.5 | 34.4 | 98.8 | 108.7 | ||||
Produced petroleum revenue (1) | 84.4 | 168.1 | 486.4 | 560.9 | ||||
Diluent and other revenue | 46.1 | 1.1 | 187.0 | 5.3 | ||||
Oil and gas sales (2) (3) | 130.5 | 169.2 | 673.4 | 566.2 |
(1) | See definition under section "Non-GAAP Financial Measures". |
(2) | Excludes realized commodity risk management from financial contracts. |
(3) | Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements. |
($ millions) | Light oil | Bitumen | NGLs | Natural gas | Produced petroleum revenue | |||||
Quarter ended December 31, 2016 (1) | 58.1 | 53.0 | 22.6 | 34.4 | 168.1 | |||||
Effect of change in product prices and differentials | 0.3 | 4.5 | 2.1 | 0.7 | 7.6 | |||||
Effect of change in sales volumes | (46.6 | ) | (2.7 | ) | (19.4 | ) | (22.6 | ) | (91.3 | ) |
Quarter ended December 31, 2017 (1) | 11.8 | 54.8 | 5.3 | 12.5 | 84.4 |
(1) | Excludes realized commodity risk management from financial contracts. |
($ millions) | Light oil | Bitumen | NGLs | Natural gas | Produced petroleum revenue | |||||
Twelve months ended December 31, 2016 (1) | 215.8 | 172.2 | 64.2 | 108.7 | 560.9 | |||||
Effect of change in product prices and differentials | 23.3 | 30.0 | 19.0 | 23.7 | 96.0 | |||||
Effect of change in sales volumes | (89.8 | ) | (20.6 | ) | (26.5 | ) | (33.6 | ) | (170.5 | ) |
Twelve months ended December 31, 2017 (1) | 149.3 | 181.6 | 56.7 | 98.8 | 486.4 |
(1) | Excludes realized commodity risk management from financial contracts. |
PENGROWTH 2017 Management's Discussion and Analysis | 20 |
($ millions except per boe amounts and percentages) | Three months ended | Twelve months ended | ||||||
Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | |||||
Royalties, net of incentives | 8.0 | 14.1 | 45.8 | 40.0 | ||||
$/boe | 3.52 | 2.82 | 3.10 | 1.91 | ||||
Royalties as a percent of produced petroleum revenue (%) (1) (2) | 9.5 | 8.4 | 9.4 | 7.1 |
(1) | Excludes realized commodity risk management from financial contracts. |
(2) | See definition under section "Non-GAAP Financial Measures". |
($ millions except per boe amounts) | Three months ended | Twelve months ended | ||||||
Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | |||||
Operating expenses (1) | 30.1 | 70.0 | 217.5 | 275.4 | ||||
Less: Processing income (2) | 2.2 | n/a | 19.1 | n/a | ||||
Net operating expenses (3) | 27.9 | 70.0 | 198.4 | 275.4 | ||||
$/boe | 12.28 | 14.00 | 13.45 | 13.19 |
(1) | Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements. |
(2) | Processing income for the three and twelve months ended December 31, 2016 was $7.3 million and $27.4 million, respectively. Operating expenses for 2016 were not restated as a result of IFRS 15 adoption consistent with the cumulative effect approach. |
(3) | See definition under section "Non-GAAP Financial Measures". |
PENGROWTH 2017 Management's Discussion and Analysis | 21 |
Three months ended | Twelve months ended | |||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||
Diluent purchases | 41.4 | n/a | 147.2 | n/a | ||
Other product purchases | 1.3 | n/a | 16.3 | n/a | ||
Diluent and other purchases (1) | 42.7 | n/a | 163.5 | n/a |
(1) | Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements. |
($ millions except per boe amounts) | Three months ended | Twelve months ended | ||||||
Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | |||||
Transportation expenses | 5.4 | 8.2 | 27.1 | 33.7 | ||||
$/boe | 2.38 | 1.64 | 1.84 | 1.61 |
Three months ended | Twelve months ended | |||||||
Operating Netbacks ($/boe) (1) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Produced petroleum revenue | 37.14 | 33.62 | 32.96 | 26.86 | ||||
Royalties | (3.52 | ) | (2.82 | ) | (3.10 | ) | (1.91 | ) |
Net operating expenses | (12.28 | ) | (14.00 | ) | (13.45 | ) | (13.19 | ) |
Transportation expenses | (2.38 | ) | (1.64 | ) | (1.84 | ) | (1.61 | ) |
Operating netbacks before realized commodity risk management | 18.96 | 15.16 | 14.57 | 10.15 | ||||
Realized commodity risk management | (2.90 | ) | 15.44 | (1.34 | ) | 18.47 | ||
Operating netbacks ($/boe) | 16.06 | 30.60 | 13.23 | 28.62 |
(1) | See definition under section "Non-GAAP Financial Measures". |
PENGROWTH 2017 Management's Discussion and Analysis | 22 |
Three months ended | Twelve months ended | |||||||
($ millions except per boe amounts) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Cash G&A expenses (1) | 12.6 | 17.8 | 56.6 | 70.4 | ||||
$/boe | 5.54 | 3.56 | 3.84 | 3.37 | ||||
Non-cash G&A expenses (1) | (1.3 | ) | 3.8 | 4.9 | 13.2 | |||
$/boe | (0.57 | ) | 0.76 | 0.33 | 0.63 | |||
Total G&A (1) | 11.3 | 21.6 | 61.5 | 83.6 | ||||
$/boe | 4.97 | 4.32 | 4.17 | 4.00 | ||||
($ millions) | ||||||||
Cash G&A before share based compensation expense (1) | 13.2 | 17.1 | 57.4 | 65.1 | ||||
Share based compensation expense (1): | ||||||||
Cash-settled share based compensation | (0.6 | ) | 0.7 | (0.8 | ) | 5.3 | ||
Share-settled share based compensation | (1.3 | ) | 3.8 | 4.9 | 13.2 | |||
Total share based compensation expense | (1.9 | ) | 4.5 | 4.1 | 18.5 | |||
Total G&A (1) | 11.3 | 21.6 | 61.5 | 83.6 |
(1) | Net of recoveries and capitalization, as applicable. |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Severance costs | 1.3 | — | 10.5 | — | ||||
Onerous office lease contracts | 18.5 | — | 26.5 | — | ||||
Total restructuring costs | 19.8 | — | 37.0 | — |
PENGROWTH 2017 Management's Discussion and Analysis | 23 |
Three months ended | Twelve months ended | |||||||
($ millions except per boe amounts) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Depletion, depreciation and amortization | 31.9 | 75.3 | 207.6 | 349.9 | ||||
$/boe | 14.04 | 15.06 | 14.07 | 16.76 | ||||
Accretion | 1.3 | 3.6 | 11.4 | 15.1 | ||||
$/boe | 0.57 | 0.72 | 0.77 | 0.72 |
PENGROWTH 2017 Management's Discussion and Analysis | 24 |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
PP&E impairments | — | — | 504.4 | — | ||||
E&E impairments | 130.0 | — | 130.0 | — | ||||
Total impairments | 130.0 | — | 634.4 | — |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Interest and financing charges | 13.4 | 27.0 | 74.4 | 108.5 | ||||
Capitalized interest | (1.0 | ) | (0.7 | ) | (3.7 | ) | (3.0 | ) |
Total interest and financing charges | 12.4 | 26.3 | 70.7 | 105.5 |
PENGROWTH 2017 Management's Discussion and Analysis | 25 |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Currency exchange rate (Cdn$1 = U.S.$) at beginning of period | 0.80 | 0.76 | 0.74 | 0.72 | ||||
Currency exchange rate (Cdn$1 = U.S.$) at period end | 0.80 | 0.74 | 0.80 | 0.74 | ||||
Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt (1) | (4.9 | ) | (34.8 | ) | 66.1 | 46.8 | ||
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt (1) | (0.3 | ) | 0.7 | (0.5 | ) | 5.8 | ||
Total unrealized foreign exchange gain (loss) from translation of foreign denominated debt | (5.2 | ) | (34.1 | ) | 65.6 | 52.6 | ||
Unrealized gain (loss) on U.S. foreign exchange risk management contracts (2) | 35.8 | (26.7 | ) | (15.0 | ) | (80.6 | ) | |
Unrealized gain (loss) on U.K. foreign exchange risk management contracts | 0.4 | (0.8 | ) | 0.8 | (5.4 | ) | ||
Total unrealized gain (loss) on foreign exchange risk management contracts | 36.2 | (27.5 | ) | (14.2 | ) | (86.0 | ) | |
Net unrealized foreign exchange gain (loss) | 31.0 | (61.6 | ) | 51.4 | (33.4 | ) | ||
Net realized foreign exchange gain (loss) (3) | (34.4 | ) | 46.8 | (38.4 | ) | 46.5 |
(1) | Includes both principal and interest. |
(2) | Includes both foreign exchange risk management contracts associated with the U.S. term notes and with the U.S. dollar fixed price WCS differential. |
(3) | Twelve months ended December 31, 2017 includes $37.6 million loss from settlement of foreign exchange swap contracts related to the prepayment of term notes. |
PENGROWTH 2017 Management's Discussion and Analysis | 26 |
Principal amount (U.S.$ millions) | Swapped amount (U.S.$ millions) | % of principal swapped | Average fixed rate (Cdn$1 = U.S.$) | ||||
366.3 | 255.0 | 70 | % | 0.75 |
Principal amount (U.K. pound sterling millions) | Swapped amount (U.K. pound sterling millions) | % of principal swapped (1) | Fixed rate (Cdn$1 = U.K. pound sterling) | ||||
12.1 | 15.0 | 124 | % | 0.63 |
(1) | Exceeds 100 percent as swaps were not liquidated when portion of the principal amount of term note was early repaid in the fourth quarter of 2017. |
Cdn$0.01 Exchange rate change | ||||
Foreign exchange sensitivity as at December 31, 2017 ($ millions) | Cdn - U.S. | Cdn - U.K. | ||
Unrealized foreign exchange gain or loss on foreign denominated debt | 3.7 | 0.1 | ||
Unrealized foreign exchange risk management gain or loss | 2.6 | 0.1 | ||
Net pre-tax impact on Consolidated Statements of Income (Loss) | 1.1 | — |
PENGROWTH 2017 Management's Discussion and Analysis | 27 |
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Change | |||
ARO, beginning of year | 652.3 | 703.4 | (51.1 | ) | ||
Expenditures on remediation/provisions settled | (15.9 | ) | (20.0 | ) | 4.1 | |
ARO on dispositions | (420.4 | ) | (11.8 | ) | (408.6 | ) |
Incurred during the period | 5.4 | — | 5.4 | |||
Accretion | 11.4 | 15.1 | (3.7 | ) | ||
Other revisions | 3.9 | (34.4 | ) | 38.3 | ||
ARO, end of year (1) | 236.7 | 652.3 | (415.6 | ) |
(1) | Expected to be funded from the SOEP remediation trust funds of $111.6 million at December 31, 2017, and $125.1 million remaining to be funded with future cash flows. |
PENGROWTH 2017 Management's Discussion and Analysis | 28 |
1. | the complete phase-out of coal-fired sources of electricity by 2030; |
2. | an Alberta economy-wide price on GHG emissions of $30/tonne; |
3. | capping oil sands emissions to a province-wide total of 100 megatonnes per year, with certain exceptions for cogeneration power sources and new upgrading capacity; and |
4. | reducing methane emissions from oil and gas activities by 45 percent by 2025. |
• | It replaces the current SGER as of January 1, 2018; |
• | There will be a phase in period with transition exemptions for 2018 (50 percent) and 2019 (75 percent) - meaning that compliance payments will be adjusted by the respective percentages for these first 2 years of operation under the CCIR; |
• | A facility can only use 40 percent of existing Emission Performance Credits (“EPCs”) in inventory to meet compliance. EPCs in inventory that were generated prior to 2014 will expire in 2021. EPC’s generated between 2014 and 2016 will expire in 2022 and EPC’s generated from 2017 and later will expire after 8 years; |
• | The CCIR will be based on industry sector emission performance per unit of production type - Output Based Allocation ("OBA"); |
• | The OBA benchmarks will be based on the average of 2013, 2014 and 2015 CO2e emissions. |
PENGROWTH 2017 Management's Discussion and Analysis | 29 |
Three months ended | Twelve months ended | |||||||
($ millions) | Dec 31, 2017 | Dec 31, 2016 | Dec 31, 2017 | Dec 31, 2016 | ||||
Property acquisitions | (0.1 | ) | — | (0.1 | ) | (1.3 | ) | |
Proceeds from property dispositions (1) | 118.4 | 10.6 | 910.2 | 60.2 | ||||
Net cash proceeds from dispositions | 118.3 | 10.6 | 910.1 | 58.9 |
(1) | Proceeds are net of transaction costs, closing adjustments and, where applicable, deferred proceeds. |
PENGROWTH 2017 Management's Discussion and Analysis | 30 |
2017 | 2016 | |||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||
Oil and gas sales ($ millions) (1) | 130.5 | 125.1 | 197.9 | 219.9 | 169.2 | 145.6 | 137.2 | 114.2 | ||||||||
Net income (loss) ($ millions) | (210.4 | ) | (144.7 | ) | (242.4 | ) | (86.3 | ) | (92.4 | ) | (52.9 | ) | (173.4 | ) | 25.0 | |
Net income (loss) per share ($) | (0.38 | ) | (0.26 | ) | (0.44 | ) | (0.16 | ) | (0.17 | ) | (0.10 | ) | (0.32 | ) | 0.05 | |
Net income (loss) per share - diluted ($) | (0.38 | ) | (0.26 | ) | (0.44 | ) | (0.16 | ) | (0.17 | ) | (0.10 | ) | (0.32 | ) | 0.05 | |
Funds flow from operations ($ millions) (2) (3) (4) (5) | 13.5 | (0.3 | ) | 29.3 | 26.9 | 111.7 | 122.7 | 89.1 | 106.2 | |||||||
Daily production (boe/d) | 24,702 | 35,072 | 49,349 | 52,957 | 54,354 | 55,137 | 56,735 | 62,056 | ||||||||
Produced petroleum revenue ($/boe) (1) (6) | 37.14 | 28.08 | 32.56 | 34.66 | 33.62 | 28.45 | 26.32 | 19.94 | ||||||||
Operating netback ($/boe) (6) (7) | 16.06 | 11.06 | 13.16 | 13.43 | 30.60 | 31.88 | 25.21 | 27.03 |
(1) | Excludes realized commodity risk management from financial contracts. Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements. |
(2) | First quarter of 2017 funds flow from operations includes a $12.7 million loss related to the early settlement of commodity risk management contracts. |
(3) | Fourth quarter of 2016 funds flow from operations includes $35.6 million of gains related to the early settlement of commodity risk management contracts and excludes $47.0 million related to the settlement of foreign exchange swap contracts as this was considered a financing activity. |
(4) | Third quarter of 2016 funds flow from operations includes $41.6 million of gains related to early settlement of commodity risk management contracts. |
(5) | Fourth quarter of 2017 funds flow from operations excludes $34.8 million loss related to the settlement of foreign exchange swap contracts as this was considered a financing activity. |
(6) | See definition under section "Non-GAAP Financial Measures". |
(7) | Includes realized commodity risk management. |
PENGROWTH 2017 Management's Discussion and Analysis | 31 |
Twelve months ended December 31 | ||||||
($ millions unless otherwise indicated) | 2017 | 2016 | 2015 | |||
Oil and gas sales (1) | 673.4 | 566.2 | 830.8 | |||
Net income (loss) | (683.8 | ) | (293.7 | ) | (1,093.1 | ) |
Net income (loss) per share ($) | (1.24 | ) | (0.54 | ) | (2.02 | ) |
Net income (loss) per share - diluted ($) | (1.24 | ) | (0.54 | ) | (2.02 | ) |
Dividends declared per share ($) | — | — | 0.19 | |||
Total assets | 1,910.9 | 4,117.1 | 4,562.9 | |||
Long term debt (2) | 610.5 | 1,687.3 | 1,852.8 | |||
Shareholders' equity | 806.2 | 1,485.0 | 1,765.0 | |||
Number of shares outstanding at year end (thousands) | 552,246 | 547,709 | 543,033 |
(1) | Excluding realized commodity risk management from financial contracts. Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements. |
(2) | Includes current and long term portions of long term debt and convertible debentures, as applicable. |
($ millions) | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | |||||||
Long term debt (1) | — | 164.9 | 118.3 | — | 127.6 | 199.7 | 610.5 | |||||||
Interest payments on long term debt (2) | 39.6 | 33.8 | 23.7 | 20.2 | 18.6 | 22.1 | 158.0 | |||||||
Operating leases (3) | 7.1 | 9.3 | 9.7 | 9.6 | 9.6 | 18.7 | 64.0 | |||||||
Pipeline transportation | 27.8 | 28.2 | 29.7 | 30.1 | 30.2 | 76.3 | 222.3 | |||||||
Other | 14.0 | 0.3 | 0.3 | 0.2 | 0.2 | 3.5 | 18.5 | |||||||
88.5 | 236.5 | 181.7 | 60.1 | 186.2 | 320.3 | 1,073.3 |
(1) | The debt repayment includes foreign denominated fixed rate debt translated using the year end exchange rate and excludes related foreign exchange risk management contracts. |
(2) | Interest payments are calculated at fixed rate debt interest rates and December 31, 2017 period end exchange rate. |
(3) | Includes office rent and other commitments. |
PENGROWTH 2017 Management's Discussion and Analysis | 32 |
• | The prices of Pengrowth’s products (crude oil, bitumen, natural gas and NGLs) fluctuate due to many factors including local and global market supply and demand, weather patterns, availability of pipeline and rail transportation capacity, availability of refining capacity, discount for Western Canadian light oil, bitumen and natural gas, and political and economic stability. |
• | Production could be shut-in at specific wells or fields in times of low commodity prices or lack of available shipping capacity. |
• | Substantial and sustained reductions in commodity prices or equity and debt markets, including Pengrowth’s share price, in some circumstances could result in Pengrowth recording an impairment loss as well as affect Pengrowth’s ability to spend capital, develop its properties, reinstate or maintain a dividend on its shares, service its debt and meet its other obligations. An impairment test is sensitive to lower realized commodity prices, which have been under significant downward pressure in recent years. Declines in commodity prices could result in impairment charges as the cushions in the CGU impairment tests have been eroded by commodity price decreases. |
• | Capital markets may restrict Pengrowth’s access to capital and raise its cost of capital and borrowing costs. To the extent that external sources of capital become limited or cost prohibitive, Pengrowth’s ability to fund future development and acquisition opportunities and to repay or refinance indebtedness when due may be impaired. |
• | Pengrowth is exposed to third party credit risk through its oil and gas sales, financial hedging transactions and joint venture activities. The failure of any counterparties to meet their contractual obligations could adversely impact Pengrowth. |
• | 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 most circumstances, being in default of one loan will result in other loans also being in default and restrict access to the Credit Facility. If an event of non-compliance occurs and cannot be remedied during an applicable remedy period, if any, Pengrowth would have to repay the relevant debt, refinance the debt or negotiate new terms with the debt holders. |
• | In event of default on Pengrowth's debt, the net proceeds of any foreclosure sale would be allocated to the repayment of the lenders, note holders and other creditors and only the remainder, if any, would be available for distribution to the shareholders. |
• | Uncertainty in international financial markets could lead to constrained capital markets, increased cost of capital and negative impact on economic activity and commodity prices. |
• | Government royalties, income taxes, commodity and other taxes, levies, fees and any audits may have a significant economic impact on Pengrowth’s financial results. Changes to federal and provincial legislation governing such royalties, taxes and fees could have a material impact on Pengrowth’s financial results and the value of Pengrowth’s common shares. |
• | 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, Pengrowth may be required to incur significant costs to comply with future regulations to reduce greenhouse gas and other emissions. |
• | Regulations surrounding the fracture stimulation of wells, including increasing disclosure and restrictions, differ and depend on the area of operation. Pengrowth may have to adjust its operational practices, increase compliance and incur additional costs as a result. |
PENGROWTH 2017 Management's Discussion and Analysis | 33 |
• | Changes to accounting policies may result in significant adjustments to Pengrowth's financial results, which could negatively impact Pengrowth's business, including increasing the risk of failing a financial covenant contained within the Credit Facility or term debt. |
• | The marketability of Pengrowth's production depends in part upon the availability, proximity and capacity of gathering systems, pipelines, rail lines and processing facilities. Operational or economic factors may result in the inability to deliver the products to market. |
• | Competition for properties could drive the cost of acquisitions up and expected returns from the properties down. |
• | Timing of oil and gas operations is dependent on gaining timely access to lands. Consultations, that are mandated by governing authorities, with all stakeholders (including surface owners, First Nations and all interested parties) are becoming increasingly time consuming and complex, and have a direct impact on cycle times. |
• | Limitations on the availability of specialized equipment, goods and services, during periods of increased activity within the oil and gas sector, may adversely impact timing of operations. |
• | Oil and gas operations can be negatively impacted by certain weather conditions, including floods, forest fires and other natural events, which may restrict production and/or delay drilling activities. |
• | Some of Pengrowth’s properties are operated by third parties whereby Pengrowth has less control over the pace of capital and operating expenditures. If these operators fail to perform their duties properly, or become insolvent, Pengrowth 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. |
• | Geological and operational risks affect the quantity and quality of reserves and the costs of recovering those reserves. Pengrowth's actual results will vary from the reserve estimates and those variations could be material. |
• | 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. |
• | Delays in business operations could adversely affect the market price of the common shares. |
• | During periods of increased activity within the oil and gas sector, the cost of goods and services may increase substantially and it may be more difficult to hire and retain staff and the cost for skilled labour may increase substantially. |
• | Attacks against facilities, or the threat thereof, may have an adverse impact on Pengrowth and the implementation of security measures as a precaution against possible attacks would result in increased cost to Pengrowth’s business. |
• | Actual production and reserves will vary from estimates, and those variations could be material and may negatively affect the market price of the common shares. |
• | Delays or failure to secure regulatory approvals for projects may result in capital being spent with reduced economics, reduced or no further reserves being booked, and reduced or no associated future production and cash flow. |
• | The Corporation has substantial future asset retirement obligations. There is a risk that the magnitude of these payments may be larger than expected and that the timing of such payments may accelerate. Either of these factors could increase financial costs for the Corporation. |
• | The performance and results of a thermal project such as Lindbergh is dependent on the ability of the steam to access the reservoir and efficiently move additional bitumen that would otherwise remain trapped within the reservoir rock. The amount and cost of steam required, the additional oil recovered, the quality of the oil produced, the ability to recycle produced water into steam and the ability to manage costs will determine the economic viability for a thermal project. |
• | The success of a thermal project such as Lindbergh will depend, in part, on Pengrowth's ability to sell the production at a desirable price. Current transportation and refining constraints have resulted in a volatile price environment with a substantial discount (differential) being paid for bitumen. |
• | Capital re-investment on Pengrowth's existing assets may not yield the expected benefits and related value creation. Drilling opportunities may prove to be more costly or less productive than anticipated. |
PENGROWTH 2017 Management's Discussion and Analysis | 34 |
• | Pengrowth’s oil and gas reserves will be depleted over time and the level of cash flow from operations and the value of Pengrowth's common shares could materially decrease if reserves and production are not replaced. The ability to replace production depends on the amount of capital invested and success in developing existing reserves, acquiring new reserves and financing this development and acquisition activity within the context of the capital markets. |
• | Incorrect assessments of value at the time of acquisitions could adversely affect the value of Pengrowth’s common shares. |
• | The market price of the common shares could be adversely affected by unforeseen title defects. |
• | With the sale of over $2.3 billion of assets since 2012, in part to fund the first commercial phase of Lindbergh, Pengrowth's assets have become less diversified and increasingly concentrated in one project (Lindbergh), product type (bitumen) and one area/formation (the Lloydminster formation). A failure to execute at Lindbergh (whether as a result of capital constraints, operational issues or otherwise) or any of the Corporation's remaining core properties could have a significant adverse effect on Pengrowth. |
• | Pengrowth has substantial exposure to the U.S. dollar. Any decrease in the Canadian dollar relative to the U.S. dollar results in an increase in the Canadian dollar equivalent of Pengrowth’s U.S. dollar denominated term debt as Pengrowth reports and prepares its covenant calculations in Canadian dollars. A significant decrease in the value of the Canadian dollar relative to the U.S. dollar could cause Pengrowth to be in violation of its debt covenants resulting in Pengrowth being in default under its borrowing agreements. |
• | Investors’ interest in the oil and gas sector change over time which affects the availability of capital and the value of Pengrowth common shares. |
• | Pengrowth is subject to a variety of information technology and system risks, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of our information technology systems by third parties or insiders which could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to our business activities or our competitive position. It could also result in material financial loss, regulatory action and sanctions, reputational harm and/or legal liability, which, in turn, could materially adversely affect our business, financial condition or profitability. |
• | Inflation may result in escalating costs, which could impact the value of Pengrowth's common shares. |
• | Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs. Pengrowth is also exposed to foreign currency fluctuations on the U.S. dollar denominated term debt for both interest and principal payments. |
• | Failure to receive regulatory approval or the expiry of the rights to explore for E&E assets could lead to the impairment of E&E assets. |
PENGROWTH 2017 Management's Discussion and Analysis | 35 |
PENGROWTH 2017 Management's Discussion and Analysis | 36 |
PENGROWTH 2017 Management's Discussion and Analysis | 37 |
PENGROWTH 2017 Management's Discussion and Analysis | 38 |
![]() | ![]() |
Derek W. Evans | Christopher G. Webster |
President and Chief Executive Officer | Chief Financial Officer |
PENGROWTH 2017 Financial Results | 1 |
PENGROWTH 2017 Financial Results | 2 |
PENGROWTH 2017 Financial Results | 3 |
PENGROWTH 2017 Financial Results | 4 |
PENGROWTH 2017 Financial Results | 5 |
As at | As at | |||||||
December 31, 2017 | December 31, 2016 | |||||||
Note | As adjusted * | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 1.1 | $ | 286.7 | ||||
Accounts receivable | 105.7 | 126.6 | ||||||
Fair value of risk management contracts | 17 | — | 2.9 | |||||
Other assets | 4 | 24.0 | — | |||||
Assets held for sale | 5 | — | 117.5 | |||||
130.8 | 533.7 | |||||||
Fair value of risk management contracts | 17 | 1.9 | 1.0 | |||||
Other assets | 4 | 99.8 | 118.7 | |||||
Property, plant and equipment | 5 | 1,104.2 | 2,849.0 | |||||
Exploration and evaluation assets | 6 | 232.0 | 496.3 | |||||
Deferred income taxes | 11 | 342.2 | 118.4 | |||||
TOTAL ASSETS | $ | 1,910.9 | $ | 4,117.1 | ||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 136.2 | $ | 189.6 | ||||
Fair value of risk management contracts | 17 | 40.0 | 55.3 | |||||
Convertible debentures | 7 | — | 126.6 | |||||
Current portion of long term debt | 8 | — | 537.0 | |||||
Current portion of provisions and other liabilities | 10 | 35.2 | 22.1 | |||||
211.4 | 930.6 | |||||||
Fair value of risk management contracts | 17 | 18.6 | 5.3 | |||||
Long term debt | 8 | 610.5 | 1,023.7 | |||||
Provisions and other liabilities | 10 | 264.2 | 672.5 | |||||
1,104.7 | 2,632.1 | |||||||
Shareholders' Equity | ||||||||
Shareholders' capital | 12 | 4,829.7 | 4,815.1 | |||||
Contributed surplus | 13.3 | 22.9 | ||||||
Deficit | (4,036.8 | ) | (3,353.0 | ) | ||||
806.2 | 1,485.0 | |||||||
Commitments and contingencies | 19, 20 | |||||||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 1,910.9 | $ | 4,117.1 |
![]() | ![]() |
Director | Director |
PENGROWTH 2017 Financial Results | 6 |
Year ended December 31 | ||||||||
2017 | 2016 | |||||||
Note | As adjusted * | |||||||
REVENUES | ||||||||
Oil and gas sales | 2, 14 | $ | 673.4 | $ | 566.2 | |||
Royalties, net of incentives | (45.8 | ) | (40.0 | ) | ||||
627.6 | 526.2 | |||||||
Realized gain (loss) on commodity risk management | 17 | (19.8 | ) | 385.7 | ||||
Change in fair value of commodity risk management contracts | 17 | 14.2 | (424.5 | ) | ||||
622.0 | 487.4 | |||||||
EXPENSES | ||||||||
Operating | 2, 14 | 217.5 | 275.4 | |||||
Diluent and other purchases | 2, 14 | 163.5 | — | |||||
Transportation | 27.1 | 33.7 | ||||||
General and administrative | 61.5 | 83.6 | ||||||
Depletion, depreciation and amortization | 5 | 207.6 | 349.9 | |||||
Impairment | 5, 6 | 634.4 | — | |||||
1,311.6 | 742.6 | |||||||
OPERATING INCOME (LOSS) | (689.6 | ) | (255.2 | ) | ||||
Other (income) expense items | ||||||||
(Gain) loss on disposition of properties | 5, 6 | 62.6 | 27.1 | |||||
Unrealized foreign exchange (gain) loss | 18 | (51.4 | ) | 33.4 | ||||
Realized foreign exchange (gain) loss | 18 | 38.4 | (46.5 | ) | ||||
Interest and financing charges | 70.7 | 105.5 | ||||||
Restructuring costs | 10 | 37.0 | — | |||||
Loss on extinguishment of debt | 8 | 56.7 | — | |||||
Accretion | 10 | 11.4 | 15.1 | |||||
Other (income) expense | (7.4 | ) | (2.7 | ) | ||||
INCOME (LOSS) BEFORE TAXES | (907.6 | ) | (387.1 | ) | ||||
Deferred income tax (recovery) expense | 11 | (223.8 | ) | (93.4 | ) | |||
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | $ | (683.8 | ) | $ | (293.7 | ) | ||
NET INCOME (LOSS) PER SHARE | 16 | |||||||
Basic | $ | (1.24 | ) | $ | (0.54 | ) | ||
Diluted | $ | (1.24 | ) | $ | (0.54 | ) |
PENGROWTH 2017 Financial Results | 7 |
Year ended December 31 | ||||||||
2017 | 2016 | |||||||
Note | As adjusted * | |||||||
CASH PROVIDED BY (USED FOR): | ||||||||
OPERATING | ||||||||
Net income (loss) and comprehensive income (loss) | $ | (683.8 | ) | $ | (293.7 | ) | ||
Non-cash items | ||||||||
Depletion, depreciation, amortization and accretion | 5, 10 | 219.0 | 365.0 | |||||
Impairment | 5, 6 | 634.4 | — | |||||
Deferred income tax (recovery) expense | 11 | (223.8 | ) | (93.4 | ) | |||
Unrealized foreign exchange (gain) loss | 18 | (51.4 | ) | 33.4 | ||||
Change in fair value of commodity risk management contracts | 17 | (14.2 | ) | 424.5 | ||||
Share based compensation | 13 | 4.9 | 13.2 | |||||
(Gain) loss on disposition of properties | 5, 6 | 62.6 | 27.1 | |||||
Restructuring costs - onerous office lease contracts | 10 | 26.5 | — | |||||
Other items | 0.9 | 0.6 | ||||||
Loss on extinguishment of debt | 8 | 56.7 | — | |||||
Foreign exchange derivative settlements | 17 | 37.6 | (47.0 | ) | ||||
Funds flow from operations | 69.4 | 429.7 | ||||||
Interest and financing charges | 70.7 | 105.5 | ||||||
Expenditures on remediation | 10 | (15.9 | ) | (20.0 | ) | |||
Change in non-cash operating working capital | 15 | 18.2 | (21.5 | ) | ||||
Cash flow from operating activities | 142.4 | 493.7 | ||||||
FINANCING | ||||||||
Bank indebtedness (repayment) | 8 | — | (3.7 | ) | ||||
Long term debt (repayment) | 8 | (937.2 | ) | (104.0 | ) | |||
Convertible debentures repayment | 7 | (126.6 | ) | — | ||||
Convertible debentures repurchase | 7 | — | (10.2 | ) | ||||
Foreign exchange derivative settlements | 17 | (37.6 | ) | 47.0 | ||||
Interest and financing charges paid | (100.8 | ) | (108.6 | ) | ||||
Cash flow from financing activities | (1,202.2 | ) | (179.5 | ) | ||||
INVESTING | ||||||||
Capital expenditures | (117.9 | ) | (64.4 | ) | ||||
Property acquisitions | (0.1 | ) | (1.3 | ) | ||||
Proceeds on property dispositions | 910.2 | 60.2 | ||||||
Contributions to remediation trust funds and other items | (10.5 | ) | (29.6 | ) | ||||
Change in non-cash investing working capital | 15 | (7.5 | ) | 7.6 | ||||
Cash flow from investing activities | 774.2 | (27.5 | ) | |||||
CHANGE IN CASH AND CASH EQUIVALENTS | (285.6 | ) | 286.7 | |||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 286.7 | — | ||||||
CASH AND CASH EQUIVALENTS AT END OF YEAR | $ | 1.1 | $ | 286.7 |
PENGROWTH 2017 Financial Results | 8 |
Year ended December 31 | ||||||||
Note | 2017 | 2016 | ||||||
As adjusted * | ||||||||
SHAREHOLDERS' CAPITAL | 12 | |||||||
Balance, beginning of year | $ | 4,815.1 | $ | 4,797.0 | ||||
Share based compensation | 14.6 | 18.1 | ||||||
Balance, end of year | 4,829.7 | 4,815.1 | ||||||
CONTRIBUTED SURPLUS | ||||||||
Balance, beginning of year | 22.9 | 27.3 | ||||||
Share based compensation | 13 | 5.0 | 13.7 | |||||
Exercise of share based compensation awards | (14.6 | ) | (18.1 | ) | ||||
Balance, end of year | 13.3 | 22.9 | ||||||
DEFICIT | ||||||||
Balance, beginning of year | (3,353.0 | ) | (3,059.3 | ) | ||||
Net income (loss) | (683.8 | ) | (293.7 | ) | ||||
Balance, end of year | (4,036.8 | ) | (3,353.0 | ) | ||||
TOTAL SHAREHOLDERS' EQUITY | $ | 806.2 | $ | 1,485.0 |
PENGROWTH 2017 Financial Results | 9 |
1. | BUSINESS OF THE CORPORATION |
2. | SIGNIFICANT ACCOUNTING POLICIES |
PENGROWTH 2017 Financial Results | 10 |
2017 | ||||||
Q1 | Q2 | Q3 | ||||
Oil and gas sales as previously reported | 166.5 | 147.2 | 91.5 | |||
Diluent and other sales | 46.7 | 45.2 | 28.9 | |||
Processing income | 6.7 | 5.5 | 4.7 | |||
Adjusted Oil and gas sales | 219.9 | 197.9 | 125.1 | |||
Diluent and other purchases as previously reported | — | — | — | |||
Cost of diluent and other purchases | 46.7 | 45.2 | 28.9 | |||
Adjusted Diluent and other purchases | 46.7 | 45.2 | 28.9 | |||
Operating expenses as previously reported | 60.6 | 63.0 | 46.9 | |||
Processing income | 6.7 | 5.5 | 4.7 | |||
Adjusted operating expenses | 67.3 | 68.5 | 51.6 |
• | Sales from the production of, and royalty (and gross overriding royalty) interests in, light oil, natural gas, natural gas liquids, sulphur and from the sale of diluted bitumen and purchased products; |
• | Fees charged to third parties for processing and other services (i.e. gas and other product processing, contract operating etc.) provided at facilities where Pengrowth has an ownership interest. |
PENGROWTH 2017 Financial Results | 11 |
PENGROWTH 2017 Financial Results | 12 |
- | Office equipment | 60 months |
- | Leasehold improvements and finance leases | Lease term/Useful life |
- | Computers | 36 months |
- | Deferred hydrocarbon injectants | 24 months |
- | Motor vehicles | 60 months |
• | The fulfillment of the arrangement is dependent on the use of a specific asset or assets; and |
• | The arrangement contains the right to use the asset(s). |
PENGROWTH 2017 Financial Results | 13 |
PENGROWTH 2017 Financial Results | 14 |
PENGROWTH 2017 Financial Results | 15 |
PENGROWTH 2017 Financial Results | 16 |
• | Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. |
• | Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. |
• | Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. |
PENGROWTH 2017 Financial Results | 17 |
PENGROWTH 2017 Financial Results | 18 |
3. | ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED |
PENGROWTH 2017 Financial Results | 19 |
4. | OTHER ASSETS |
As at | ||||||
December 31, 2017 | December 31, 2016 | |||||
Remediation trust funds - current | $ | 24.0 | $ | — | ||
Remediation trust funds - non-current | 87.6 | 106.5 | ||||
Prepaid tax assessment | 12.2 | 12.2 | ||||
$ | 123.8 | $ | 118.7 |
Remediation Trust Funds | |||
Balance, December 31, 2015 | $ | 79.6 | |
Contributions | 26.9 | ||
Remediation expenditures | (0.9 | ) | |
Investment income | 3.2 | ||
Unrealized gain (loss) | (2.3 | ) | |
Balance, December 31, 2016 | $ | 106.5 | |
Contributions | 14.0 | ||
Remediation expenditures | (6.6 | ) | |
Investment income | 3.1 | ||
Unrealized gain (loss) | (0.6 | ) | |
Dispositions | $ | (4.8 | ) |
Balance, December 31, 2017 | $ | 111.6 |
PENGROWTH 2017 Financial Results | 20 |
5. | PROPERTY, PLANT AND EQUIPMENT ("PP&E") |
Cost or deemed cost | Oil and natural gas assets | Other equipment | Total | ||||||
Balance, December 31, 2015 | $ | 6,973.5 | $ | 88.9 | $ | 7,062.4 | |||
Additions to PP&E | 89.9 | 1.9 | 91.8 | ||||||
Property acquisitions | 1.3 | — | 1.3 | ||||||
Change in asset retirement obligations | (34.4 | ) | — | (34.4 | ) | ||||
Divestitures | (191.5 | ) | — | (191.5 | ) | ||||
Balance, December 31, 2016 | $ | 6,838.8 | $ | 90.8 | $ | 6,929.6 | |||
Additions to PP&E | 120.7 | 0.8 | 121.5 | ||||||
Property acquisitions | 0.1 | — | 0.1 | ||||||
Change in asset retirement obligations | 9.3 | — | 9.3 | ||||||
Divestitures | (3,151.2 | ) | (3.7 | ) | (3,154.9 | ) | |||
Balance, December 31, 2017 | $ | 3,817.7 | $ | 87.9 | $ | 3,905.6 | |||
Accumulated depletion, amortization and impairment losses | Oil and natural gas assets | Other equipment | Total | ||||||
Balance, December 31, 2015 | $ | 3,639.5 | $ | 76.1 | $ | 3,715.6 | |||
Depletion and amortization for the period | 345.6 | 4.3 | 349.9 | ||||||
Divestitures | (102.4 | ) | — | (102.4 | ) | ||||
Balance, December 31, 2016 | $ | 3,882.7 | $ | 80.4 | $ | 3,963.1 | |||
Depletion and amortization for the period | 204.4 | 3.2 | 207.6 | ||||||
Impairment | 504.4 | — | 504.4 | ||||||
Divestitures | (1,871.2 | ) | (2.5 | ) | (1,873.7 | ) | |||
Balance, December 31, 2017 | $ | 2,720.3 | $ | 81.1 | $ | 2,801.4 | |||
Net book value | Oil and natural gas assets | Other equipment | Total | ||||||
As at December 31, 2017 | |||||||||
Assets held for sale | $ | — | $ | — | $ | — | |||
Long term | 1,097.4 | 6.8 | 1,104.2 | ||||||
$ | 1,097.4 | $ | 6.8 | $ | 1,104.2 | ||||
As at December 31, 2016 | |||||||||
Assets held for sale | $ | 117.5 | $ | — | $ | 117.5 | |||
Long term | 2,838.6 | 10.4 | 2,849.0 | ||||||
$ | 2,956.1 | $ | 10.4 | $ | 2,966.5 |
PENGROWTH 2017 Financial Results | 21 |
6. | EXPLORATION AND EVALUATION ASSETS ("E&E") |
Cost or deemed cost | |||
Balance, December 31, 2015 | $ | 494.8 | |
Additions | 1.5 | ||
Balance, December 31, 2016 | $ | 496.3 | |
Divestitures | (134.3 | ) | |
Impairment | (130.0 | ) | |
Balance, December 31, 2017 | $ | 232.0 |
PENGROWTH 2017 Financial Results | 22 |
(a) | Reserves. Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated. |
(c) | Discount rate. The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate cost of capital for potential acquirers of Pengrowth or Pengrowth’s CGUs. Changes in the general economic environment could result in significant changes to this estimate. |
AECO gas (1) | ||
Year | (Cdn$/MMBtu) | |
2018 | 2.20 | |
2019 | 2.54 | |
2020 | 2.88 | |
2021 | 3.24 | |
2022 | 3.47 | |
2023 | 3.58 | |
2024 | 3.66 | |
2025 | 3.73 | |
2026 | 3.80 | |
2027 | 3.88 | |
Thereafter | + 2.0 percent/yr |
(1) | Prices represent forecasted amounts as at January 1, 2018 by Pengrowth's independent reserves evaluator. |
PENGROWTH 2017 Financial Results | 23 |
7. | CONVERTIBLE DEBENTURES |
Series B - 6.25 percent | |||
Maturity date | March 31, 2017 | ||
Conversion price (per Pengrowth share) | $ | 11.51 | |
Balance, December 31, 2015 | $ | 137.0 | |
Repurchase of convertible debentures | (10.2 | ) | |
Premium accretion | (0.2 | ) | |
Balance, December 31, 2016 | $ | 126.6 | |
Repayment of convertible debentures | (126.6 | ) | |
Balance, December 31, 2017 | $ | — | |
Face value, December 31, 2017 | $ | — |
8. | LONG TERM DEBT |
• | The prepayment of all of the term notes due August 21, 2018 (U.S.$265 million and Cdn$15 million) and additional prepayments of Cdn$115.4 million of principal during the fourth quarter of 2017 on the remaining outstanding term notes. |
• | Amendments to the existing financial covenants effective for the quarter ending September 30, 2017 through to and including the quarter ending September 30, 2019 in the case of its term notes, and expiring on March 31, 2019 in the case of its Credit Facility (the "Waiver Period"). During the Waiver Period: |
◦ | The Debt to Adjusted EBITDA ratio covenant and the Debt to Book Capitalization ratio covenant do not apply. |
◦ | The trailing 12 month Adjusted EBITDA to Adjusted Interest Expense minimum ratio covenant is revised as follows: |
Year | Q1 | Q2 | Q3 | Q4 |
2017 | n/a | n/a | 4.0 times | 0.77 times |
2018 | 0.75 times | 0.68 times | 1.03 times | 1.01 times |
2019 | 1.13 times | 1.19 times | 1.23 times | 4.0 times |
• | The Lenders were granted security over Pengrowth’s assets, similar to other oil and gas borrowing base loans. |
• | The remaining outstanding term notes maturing in 2019 through 2024 are subject to a 2.0 percentage point increase in interest rates (which increases to 3.0 percentage points on January 1, 2020). A one-time amendment fee of 0.5 percent on outstanding term notes was also paid to the holders of term notes due after 2018. |
• | The aggregate credit limit under the Credit Facility was reduced to $330 million following the closing of the Swan Hills asset sale, the $50 million Demand Credit Facility was eliminated and interest rates under the Credit Facility increased by 2.0 percentage points. A one time amendment fee of 0.5 percent of the aggregate credit limit was paid to the syndicate members of the Credit Facility. |
• | The 2017 debt restructuring was a substantial modification of terms and was therefore reflected as an extinguishment of debt for accounting purposes with a Loss on extinguishment of debt reflected in the 2017 Consolidated Statement of Income (Loss) in the amount of $56.7 million composed of $55.2 million of debt restructuring costs and $1.5 million of remaining unamortized issue costs. Debt restructuring costs comprised the amendment fees, make whole payments on the principal prepayments, as well as professional fees. |
PENGROWTH 2017 Financial Results | 24 |
As at | ||||||
December 31, 2017 | December 31, 2016 | |||||
U.S. dollar denominated term notes: | ||||||
400 million at 6.35 percent due July 26, 2017 | $ | — | $ | 537.0 | ||
265 million at 6.98 percent due August 21, 2018 (1) | — | 355.6 | ||||
35 million at 5.49 percent due October 18, 2019 (2) | 35.3 | 46.9 | ||||
115.5 million at 7.98 percent due May 11, 2020 (3) | 118.3 | 154.8 | ||||
105 million at 6.07 percent due October 18, 2022 (4) | 107.1 | 140.6 | ||||
195 million at 6.17 percent due October 18, 2024 (5) | 199.7 | 261.1 | ||||
$ | 460.4 | $ | 1,496.0 | |||
U.K. pound sterling denominated term notes: | ||||||
15 million at 5.45 percent due October 18, 2019 (6) | $ | 20.6 | $ | 24.8 | ||
Canadian dollar term notes: | ||||||
15 million at 6.61 percent due August 21, 2018 (1) | $ | — | $ | 15.0 | ||
25 million at 6.74 percent due October 18, 2022 (7) | 20.5 | 24.9 | ||||
$ | 20.5 | $ | 39.9 | |||
Canadian dollar term Credit Facility borrowings | $ | 109.0 | $ | — | ||
Total long term debt | $ | 610.5 | $ | 1,560.7 | ||
Current portion of long term debt | $ | — | $ | 537.0 | ||
Non-current portion of long term debt | 610.5 | 1,023.7 | ||||
$ | 610.5 | $ | 1,560.7 |
(1) | There was no outstanding balance following the early repayment on October 12, 2017. |
(2) | The remaining balance of U.S.$28.1 million term notes were outstanding, following the early repayment of U.S.$6.9 million in the fourth quarter of 2017. |
(3) | The remaining balance of U.S.$94.1 million term notes were outstanding, following the early repayment of U.S.$21.4 million in the fourth quarter of 2017. |
(4) | The remaining balance of U.S.$85.2 million term notes were outstanding, following the early repayment of U.S.$19.8 million in the fourth quarter of 2017. |
(5) | The remaining balance of U.S.$158.9 million term notes were outstanding, following the early repayment of U.S.$36.1 million in the fourth quarter of 2017. |
(6) | The remaining balance of U.K. pound sterling 12.1 million term notes were outstanding, following the early repayment of U.K. pound sterling 2.9 million in the fourth quarter of 2017. |
(7) | The remaining balance of Cdn$20.5 million term notes were outstanding, following the early repayment of Cdn$4.5 million in the fourth quarter of 2017. |
PENGROWTH 2017 Financial Results | 25 |
9. | CAPITAL DISCLOSURES |
Year | Q1 | Q2 | Q3 | Q4 |
2017 | n/a | n/a | 4.0 times | 0.77 times |
2018 | 0.75 times | 0.68 times | 1.03 times | 1.01 times |
2019 | 1.13 times | 1.19 times | 1.23 times | 4.0 times |
PENGROWTH 2017 Financial Results | 26 |
Term Notes | Canadian dollar Term Credit Facility | Convertible debentures | |||||||
Balance December 31, 2016 | $ | 1,560.7 | $ | — | $ | 126.6 | |||
Increase (decrease) due to: | |||||||||
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt | (65.1 | ) | — | — | |||||
Credit facility borrowing | — | 109.0 | — | ||||||
Repayment | (996.0 | ) | — | (126.6 | ) | ||||
Issue cost amortization | 1.9 | — | — | ||||||
Balance, December 31, 2017 | $ | 501.5 | $ | 109.0 | $ | — |
As at | ||||||
December 31, 2017 | December 31, 2016 | |||||
Long term debt (1) | $ | 610.5 | $ | 1,560.7 | ||
Convertible debentures | — | 126.6 | ||||
Working capital (surplus) deficiency (2) | 80.6 | (266.7 | ) | |||
$ | 691.1 | $ | 1,420.6 |
(1) | Includes current portion of term notes and bank indebtedness, as applicable. |
(2) | Working capital (surplus) deficiency is calculated as current liabilities less current assets per the Consolidated Balance Sheets, excluding bank indebtedness and the current portions of long term debt and convertible debentures, as applicable. |
PENGROWTH 2017 Financial Results | 27 |
10. | PROVISIONS AND OTHER LIABILITIES |
Asset retirement obligations | Finance leases | Restructuring provision - onerous office lease contracts | Other liabilities | Total | |||||||||||
Balance, December 31, 2015 | $ | 703.4 | $ | 4.3 | $ | — | $ | 0.3 | $ | 708.0 | |||||
Incurred during the period | — | 35.0 | — | 2.9 | 37.9 | ||||||||||
Property dispositions | (11.8 | ) | — | — | — | (11.8 | ) | ||||||||
Expenditures on remediation/provisions settled | (20.0 | ) | (1.4 | ) | — | (0.1 | ) | (21.5 | ) | ||||||
Other revisions | (34.4 | ) | — | — | 1.3 | (33.1 | ) | ||||||||
Accretion (amortization) | 15.1 | — | — | — | 15.1 | ||||||||||
Balance, December 31, 2016 | $ | 652.3 | $ | 37.9 | $ | — | $ | 4.4 | $ | 694.6 | |||||
Incurred during the period | 5.4 | — | 26.5 | (1.5 | ) | 30.4 | |||||||||
Property dispositions | (420.4 | ) | (2.0 | ) | — | — | (422.4 | ) | |||||||
Expenditures on remediation/provisions settled | (15.9 | ) | (1.7 | ) | (0.3 | ) | (0.6 | ) | (18.5 | ) | |||||
Other revisions | 3.9 | — | — | — | 3.9 | ||||||||||
Accretion (amortization) | 11.4 | — | — | — | 11.4 | ||||||||||
Balance, December 31 2017 | $ | 236.7 | $ | 34.2 | $ | 26.2 | $ | 2.3 | $ | 299.4 |
As at December 31, 2017 | Asset retirement obligations | Finance leases | Restructuring provision - onerous office lease contracts | Other liabilities | Total | ||||||||||
Current | $ | 29.9 | $ | 0.9 | $ | 4.4 | $ | — | $ | 35.2 | |||||
Long term | 206.8 | 33.3 | 21.8 | 2.3 | 264.2 | ||||||||||
$ | 236.7 | $ | 34.2 | $ | 26.2 | $ | 2.3 | $ | 299.4 | ||||||
As at December 31, 2016 | |||||||||||||||
Current | $ | 20.0 | $ | 1.5 | $ | — | $ | 0.6 | $ | 22.1 | |||||
Long term | 632.3 | 36.4 | — | 3.8 | 672.5 | ||||||||||
$ | 652.3 | $ | 37.9 | $ | — | $ | 4.4 | $ | 694.6 |
As at | ||||||
December 31, 2017 | December 31, 2016 | |||||
Total escalated future costs | $ | 420.2 | $ | 2,120.4 | ||
Discount rate, per annum | 2.3 | % | 2.3 | % | ||
Inflation rate, per annum | 1.5 | % | 1.5 | % |
PENGROWTH 2017 Financial Results | 28 |
11. | DEFERRED INCOME TAXES |
Year ended December 31 | ||||||
2017 | 2016 | |||||
Income (loss) before taxes | $ | (907.6 | ) | $ | (387.1 | ) |
Combined federal and provincial tax rate | 27.08 | % | 27.09 | % | ||
Expected income tax expense (recovery) | $ | (245.8 | ) | $ | (104.9 | ) |
Change in unrecognized deferred tax asset | 22.6 | 9.8 | ||||
Foreign exchange (gain) loss (1) | (2.0 | ) | (1.8 | ) | ||
Effect of change in corporate tax rate | (0.2 | ) | — | |||
Other including share based compensation | 1.6 | 3.5 | ||||
Deferred income tax expense (recovery) | $ | (223.8 | ) | $ | (93.4 | ) |
As at | ||||||
December 31, 2017 | December 31, 2016 | |||||
Deferred tax liabilities associated with: | ||||||
PP&E and E&E assets | $ | (132.3 | ) | $ | (411.0 | ) |
Less deferred tax assets associated with: | ||||||
Non-capital losses and financing charges | 399.6 | 325.9 | ||||
Provisions | 64.1 | 176.6 | ||||
Risk management contracts | 10.8 | 14.6 | ||||
Long term debt | — | 12.1 | ||||
Convertible debentures | — | 0.2 | ||||
Net deferred tax asset (liability) | $ | 342.2 | $ | 118.4 |
As at | ||||||
December 31, 2017 | December 31, 2016 | |||||
Deductible temporary differences | $ | 204.0 | $ | 188.9 | ||
Tax losses | 109.8 | 40.2 | ||||
$ | 313.8 | $ | 229.1 |
PENGROWTH 2017 Financial Results | 29 |
Movement in deferred tax asset (liability) during the year | Balance Jan 1, 2017 | Recognized in profit or loss | Balance Dec 31, 2017 | ||||||
PP&E and E&E assets | $ | (411.0 | ) | $ | 278.7 | $ | (132.3 | ) | |
Non-capital losses and financing charges | 325.9 | 73.7 | 399.6 | ||||||
Provisions | 176.6 | (112.5 | ) | 64.1 | |||||
Risk management contracts | 14.6 | (3.8 | ) | 10.8 | |||||
Long term debt | 12.1 | (12.1 | ) | — | |||||
Convertible debentures | 0.2 | (0.2 | ) | — | |||||
Share issue costs | — | — | — | ||||||
$ | 118.4 | $ | 223.8 | $ | 342.2 |
Movement in deferred tax asset (liability) during the year | Balance Jan 1, 2016 | Recognized in profit or loss | Balance Dec 31, 2016 | ||||||
PP&E and E&E assets | (405.3 | ) | (5.7 | ) | (411.0 | ) | |||
Non-capital losses and financing charges | 328.7 | (2.8 | ) | 325.9 | |||||
Provisions | 190.2 | (13.6 | ) | 176.6 | |||||
Risk management contracts | (99.8 | ) | 114.4 | 14.6 | |||||
Long term debt | 10.8 | 1.3 | 12.1 | ||||||
Convertible debentures | 0.2 | — | 0.2 | ||||||
Share issue costs | 0.2 | (0.2 | ) | — | |||||
$ | 25.0 | $ | 93.4 | $ | 118.4 |
12. | SHAREHOLDERS’ CAPITAL |
2017 | 2016 | |||||||||
(Common shares in 000's) | Number of common shares | Amount | Number of common shares | Amount | ||||||
Balance, beginning of year | 547,709 | $ | 4,815.1 | 543,033 | $ | 4,797.0 | ||||
Share based compensation (non-cash exercised) | 4,537 | 14.6 | 4,676 | 18.1 | ||||||
Balance, end of year | 552,246 | $ | 4,829.7 | 547,709 | $ | 4,815.1 |
13. | LONG TERM INCENTIVE PLANS ("LTIP") |
PENGROWTH 2017 Financial Results | 30 |
(number of share units - 000's) | PSUs | RSUs | DSUs | |||
Outstanding, December 31, 2015 | 4,640 | 5,341 | 302 | |||
Granted | 3,049 | 6,553 | — | |||
Forfeited | (460 | ) | (737 | ) | — | |
Exercised | (1,695 | ) | (2,721 | ) | (104 | ) |
Performance adjustment | 704 | — | — | |||
Outstanding, December 31, 2016 | 6,238 | 8,436 | 198 | |||
Granted | 2,124 | 4,578 | — | |||
Forfeited | (486 | ) | (2,195 | ) | — | |
Exercised | (1,104 | ) | (3,436 | ) | — | |
Performance adjustment | (1,738 | ) | — | — | ||
Outstanding, December 31, 2017 | 5,034 | 7,383 | 198 |
PENGROWTH 2017 Financial Results | 31 |
PENGROWTH 2017 Financial Results | 32 |
(number of share units - 000's) | Cash-settled RSUs | Phantom DSUs | ||
Outstanding, December 31, 2015 | — | 397 | ||
Granted | 4,559 | 1,024 | ||
Forfeited | (330 | ) | — | |
Exercised | — | (75 | ) | |
Outstanding, December 31, 2016 | 4,229 | 1,346 | ||
Granted | 3,163 | 492 | ||
Forfeited | (3,148 | ) | — | |
Exercised | (1,341 | ) | (462 | ) |
Outstanding, December 31, 2017 | 2,903 | 1,376 |
Year ended December 31 | ||||||
2017 | 2016 | |||||
Non-cash share based compensation | $ | 5.0 | $ | 13.7 | ||
Amounts capitalized in the period | (0.1 | ) | (0.5 | ) | ||
Non-cash share based compensation expense | $ | 4.9 | $ | 13.2 | ||
Cash-settled RSUs (reduction) expense | $ | (0.2 | ) | $ | 3.6 | |
Cash-settled Phantom DSUs (reduction) expense | $ | (0.6 | ) | $ | 2.3 | |
Total share based compensation expense | $ | 4.1 | $ | 19.1 |
14. | REVENUE |
PENGROWTH 2017 Financial Results | 33 |
Year ended December 31 | |||
2017 | |||
Light oil | 149.3 | ||
Bitumen | 181.6 | ||
Natural gas liquids | 56.7 | ||
Natural gas | 98.8 | ||
Produced petroleum revenue | 486.4 | ||
Diluent | 147.2 | ||
Processing income | 19.1 | ||
Other revenue | 20.7 | ||
Total oil and gas sales | $ | 673.4 |
15. | OTHER CASH FLOW DISCLOSURES |
Year ended December 31 | ||||||
Cash provided by (used for): | 2017 | 2016 | ||||
Accounts receivable | $ | 40.9 | $ | 25.0 | ||
Accounts payable | (22.7 | ) | (43.8 | ) | ||
Prepaid tax assessment | — | (2.7 | ) | |||
$ | 18.2 | $ | (21.5 | ) |
Year ended December 31 | ||||||
Cash used for: | 2017 | 2016 | ||||
Accounts payable, including capital accruals | $ | (7.5 | ) | $ | 7.6 |
PENGROWTH 2017 Financial Results | 34 |
16. | AMOUNTS PER SHARE |
Year ended December 31 | ||||
(000's) | 2017 | 2016 | ||
Weighted average number of shares - basic and diluted | 551,193 | 546,566 |
17. | FINANCIAL INSTRUMENTS AND RISK MANAGEMENT |
Financial Crude Oil Contracts: | ||||||
Swaps | ||||||
Reference point | Term | Volume (bbl/d) | Price per bbl (U.S.$) | |||
WTI | 2018 | 8,000 | $49.97 |
PENGROWTH 2017 Financial Results | 35 |
Collars | Price per bbl (U.S.$) | ||||||||
Reference point | Term | Volume (bbl/d) | Bought Puts | Sold Calls | |||||
WTI | 2018 | 2,000 | $48.00 | $53.48 |
Crude oil swaps and collars | Cdn$1/bbl increase in future oil prices | Cdn$1/bbl decrease in future oil prices | ||||
Increase (decrease) to fair value of oil risk management contracts | ($3.5 | ) | $3.5 |
Reference point | Volume of diluted bitumen (bbl/d) | Term | Price per bbl (U.S.$) | |
Western Canada Select | 12,000 | 2018 | WTI less $16.95 | |
Western Canada Select | 5,000 | 2018 | WTI less $16.50 - $19.25 | |
Western Canada Select | 2,500 | 2019 | WTI less $17.95 | |
Western Canada Select | 5,000 | 2019 | WTI less $17.70 - $20.45 |
Principal amount (U.K. pound sterling millions) | Swapped amount (U.K. pound sterling millions) | % of principal swapped (1) | Fixed rate (Cdn$1 = U.K. pound sterling) | ||||
12.1 | 15.0 | 124 | % | 0.63 |
(1) | Exceeds 100 percent as swaps were not liquidated when portion of the principal amount of term note was early repaid in the fourth quarter of 2017. |
Principal amount (U.S.$ millions) | Swapped amount (U.S.$ millions) | % of principal swapped | Average fixed rate (Cdn$1 = U.S.$) | ||||
366.3 | 255.0 | 70 | % | 0.75 |
PENGROWTH 2017 Financial Results | 36 |
Cdn$0.01 Exchange rate change | ||||||
Foreign exchange sensitivity as at December 31, 2017 | Cdn - U.S. | Cdn - U.K. | ||||
Unrealized foreign exchange gain or loss on foreign denominated debt | $ | 3.7 | $ | 0.1 | ||
Unrealized foreign exchange risk management gain or loss | 2.6 | 0.1 | ||||
Net pre-tax impact on Consolidated Statements of Income (Loss) | $ | 1.1 | $ | — |
PENGROWTH 2017 Financial Results | 37 |
As at and for the year ended December 31, 2017 | Commodity contracts (1) | Power contracts | Foreign exchange contracts (2) | Total | ||||||||
Non-current portion of risk management assets | $ | — | $ | — | $ | 1.9 | $ | 1.9 | ||||
Current portion of risk management liabilities | (39.8 | ) | — | (0.2 | ) | (40.0 | ) | |||||
Non-current portion of risk management liabilities | — | — | (18.6 | ) | (18.6 | ) | ||||||
Risk management assets (liabilities), end of year | $ | (39.8 | ) | $ | — | $ | (16.9 | ) | $ | (56.7 | ) | |
Less: Risk management assets (liabilities) at beginning of year | (54.0 | ) | — | (2.7 | ) | (56.7 | ) | |||||
Unrealized gain (loss) on risk management contracts for the year | $ | 14.2 | $ | — | $ | (14.2 | ) | $ | — | |||
Realized gain (loss) on risk management contracts for the year | (19.8 | ) | — | (37.6 | ) | (57.4 | ) | |||||
Total unrealized and realized gain (loss) on risk management contracts for the year | $ | (5.6 | ) | $ | — | $ | (51.8 | ) | $ | (57.4 | ) | |
As at and for the year ended December 31, 2016 | Commodity contracts (1) | Power contracts (3) | Foreign exchange contracts (2) | Total | ||||||||
Current portion of risk management assets | $ | — | $ | — | $ | 2.9 | $ | 2.9 | ||||
Non-current portion of risk management assets | — | — | 1.0 | 1.0 | ||||||||
Current portion of risk management liabilities | (54.0 | ) | — | (1.3 | ) | (55.3 | ) | |||||
Non-current portion of risk management liabilities | — | — | (5.3 | ) | (5.3 | ) | ||||||
Risk management assets (liabilities), end of year | $ | (54.0 | ) | $ | — | $ | (2.7 | ) | $ | (56.7 | ) | |
Less: Risk management assets (liabilities) at beginning of year | 370.5 | (1.7 | ) | 83.3 | 452.1 | |||||||
Unrealized gain (loss) on risk management contracts for the year | $ | (424.5 | ) | $ | 1.7 | $ | (86.0 | ) | $ | (508.8 | ) | |
Realized gain (loss) on risk management contracts for the year | 385.7 | (4.5 | ) | 47.0 | 428.2 | |||||||
Total unrealized and realized gain (loss) on risk management contracts for the year | $ | (38.8 | ) | $ | (2.8 | ) | $ | (39.0 | ) | $ | (80.6 | ) |
(1) | Unrealized and realized gains and losses are presented as separate line items in the Consolidated Statements of Income (Loss). |
(2) | Unrealized and realized gains and losses are included as part of separate line items in the Consolidated Statements of Income (Loss). |
(3) | Unrealized gains and losses are included in other (income) expense. Realized gains and losses are included in operating expense. |
PENGROWTH 2017 Financial Results | 38 |
Fair value measurements using: | |||||||||||||||
As at December 31, 2017 | Carrying amount | Fair value | Quoted prices in active markets (Level 1) | Significant other observable inputs (Level 2) | Significant unobservable inputs (Level 3) | ||||||||||
Financial Assets | |||||||||||||||
Remediation trust funds | $ | 111.6 | $ | 111.6 | $ | 111.6 | $ | — | $ | — | |||||
Fair value of risk management contracts | 1.9 | 1.9 | — | 1.9 | — | ||||||||||
Financial Liabilities | |||||||||||||||
U.S. dollar denominated term notes | 460.4 | 509.5 | — | 509.5 | — | ||||||||||
Cdn dollar term notes | 20.5 | 22.8 | — | 22.8 | — | ||||||||||
U.K. pound sterling denominated term notes | 20.6 | 21.7 | — | 21.7 | — | ||||||||||
Fair value of risk management contracts | 58.6 | 58.6 | — | 58.6 | — | ||||||||||
Fair value measurements using: | |||||||||||||||
As at December 31, 2016 | Carrying amount | Fair value | Quoted prices in active markets (Level 1) | Significant other observable inputs (Level 2) | Significant unobservable inputs (Level 3) | ||||||||||
Financial Assets | |||||||||||||||
Remediation trust funds | $ | 106.5 | $ | 106.5 | $ | 106.5 | $ | — | $ | — | |||||
Fair value of risk management contracts | 3.9 | 3.9 | — | 3.9 | — | ||||||||||
Financial Liabilities | |||||||||||||||
Convertible debentures | 126.6 | 126.7 | 126.7 | — | — | ||||||||||
U.S. dollar denominated senior unsecured notes | 1,496.0 | 1,527.7 | — | 1,527.7 | — | ||||||||||
Cdn dollar senior unsecured notes | 39.9 | 41.3 | — | 41.3 | — | ||||||||||
U.K. pound sterling denominated unsecured notes | 24.8 | 25.5 | — | 25.5 | — | ||||||||||
Fair value of risk management contracts | 60.6 | 60.6 | — | 60.6 | — |
PENGROWTH 2017 Financial Results | 39 |
As at | ||||||
December 31, 2017 | December 31, 2016 | |||||
Trade | $ | 97.5 | $ | 110.3 | ||
Prepaid and other | 8.2 | 16.3 | ||||
$ | 105.7 | $ | 126.6 |
PENGROWTH 2017 Financial Results | 40 |
As at December 31, 2017 | Carrying amount | Contractual cash flows | Year 1 | Year 2 | Years 3-5 | More than 5 years | ||||||||||||
Accounts payable | $ | 136.2 | $ | 136.2 | $ | 136.2 | $ | — | $ | — | $ | — | ||||||
Commodity risk management contracts | 39.8 | 39.8 | 39.8 | — | — | — | ||||||||||||
Cdn dollar senior unsecured notes (2) | 20.5 | 27.1 | 1.4 | 1.4 | 24.3 | — | ||||||||||||
U.S. dollar denominated term notes (1) | 460.4 | 601.3 | 30.2 | 65.2 | 284.0 | 221.9 | ||||||||||||
U.K. pound sterling denominated term notes (1) | 20.6 | 22.6 | 1.1 | 21.5 | — | — | ||||||||||||
Cdn dollar term Credit Facility borrowings (2) | 109.0 | 117.6 | 6.9 | 110.7 | — | — | ||||||||||||
Finance leases | 34.2 | 76.8 | 4.4 | 4.2 | 12.6 | 55.6 | ||||||||||||
Foreign exchange risk management contracts | 18.8 | 20.8 | 0.2 | 4.3 | 16.3 | — | ||||||||||||
Other liabilities | 2.3 | 3.2 | — | 1.4 | 0.3 | 1.5 |
(1) | Contractual cash flows include future interest payments and term notes calculated at December 31, 2017 period end exchange rate. |
(2) | Contractual cash flows include future interest payments. |
As at December 31, 2016 | Carrying amount | Contractual cash flows | Year 1 | Year 2 | Years 3-5 | More than 5 years | ||||||||||||
Accounts payable | $ | 189.6 | $ | 189.6 | $ | 189.6 | $ | — | $ | — | $ | — | ||||||
Convertible debentures | 126.6 | 130.5 | 130.5 | — | — | — | ||||||||||||
Commodity risk management contracts | 54.0 | 54.0 | 54.0 | — | — | — | ||||||||||||
Cdn dollar senior unsecured notes (1) | 39.9 | 48.5 | 2.2 | 16.8 | 3.6 | 25.9 | ||||||||||||
U.S. dollar denominated senior unsecured notes (1) | 1,496.0 | 1,726.8 | 623.7 | 399.2 | 266.0 | 437.9 | ||||||||||||
U.K. pound sterling denominated unsecured notes (1) | 24.8 | 27.3 | 0.9 | 0.9 | 25.5 | — | ||||||||||||
Finance leases | 37.9 | 90.7 | 5.7 | 5.0 | 14.2 | 65.8 | ||||||||||||
Foreign exchange risk management contracts | 6.6 | 6.1 | 1.3 | 1.7 | 2.4 | 0.7 | ||||||||||||
Other liabilities | 4.4 | 8.3 | 0.6 | 2.9 | 2.8 | 2.0 | ||||||||||||
Remediation trust fund payments | — | 12.5 | 0.3 | 0.3 | 0.9 | 11.0 |
(1) | Contractual cash flows include future interest payments and senior unsecured notes calculated at December 31, 2016 period end exchange rate. |
PENGROWTH 2017 Financial Results | 41 |
As at | ||||||
Gross amounts | December 31, 2017 | December 31, 2016 | ||||
Risk management contracts | ||||||
Current asset | $ | — | $ | 3.0 | ||
Non-current asset | 1.9 | 1.0 | ||||
Current liability | (40.0 | ) | (55.4 | ) | ||
Non-current liability | (18.6 | ) | (5.3 | ) | ||
$ | (56.7 | ) | $ | (56.7 | ) |
18. | FOREIGN EXCHANGE (GAIN) LOSS |
Year ended December 31 | ||||||
2017 | 2016 | |||||
Currency exchange rate (Cdn$1 = U.S.$) at beginning of year | $ | 0.74 | $ | 0.72 | ||
Currency exchange rate (Cdn$1 = U.S.$) at year end | $ | 0.80 | $ | 0.74 | ||
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt (1) | $ | (66.1 | ) | $ | (46.8 | ) |
Unrealized foreign exchange (gain) loss on U.K. pound sterling denominated debt (1) | 0.5 | (5.8 | ) | |||
Total unrealized foreign exchange (gain) loss from translation of foreign denominated debt | $ | (65.6 | ) | $ | (52.6 | ) |
Unrealized (gain) loss on U.S. foreign exchange risk management contracts (2) | $ | 15.0 | $ | 80.6 | ||
Unrealized (gain) loss on U.K. foreign exchange risk management contracts | (0.8 | ) | 5.4 | |||
Total unrealized (gain) loss on foreign exchange risk management contracts | $ | 14.2 | $ | 86.0 | ||
Net unrealized foreign exchange (gain) loss | $ | (51.4 | ) | $ | 33.4 | |
Net realized foreign exchange (gain) loss (3) | $ | 38.4 | $ | (46.5 | ) |
(1) | Includes both principal and interest. |
(2) | Includes both foreign exchange risk management contracts associated with the U.S. denominated term notes and with the fixed price WCS differential. |
(3) | Year ended December 31, 2017 includes $37.6 million loss from settlement of foreign exchange swap contracts related to the prepayment of term notes. |
19. | COMMITMENTS |
2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | |||||||||||||||
Long term debt (1) | $ | — | $ | 164.9 | $ | 118.3 | $ | — | $ | 127.6 | $ | 199.7 | $ | 610.5 | |||||||
Interest payments on long term debt (2) | 39.6 | 33.8 | 23.7 | 20.2 | 18.6 | 22.1 | 158.0 | ||||||||||||||
Operating leases (3) | 7.1 | 9.3 | 9.7 | 9.6 | 9.6 | 18.7 | 64.0 | ||||||||||||||
Pipeline transportation | 27.8 | 28.2 | 29.7 | 30.1 | 30.2 | 76.3 | 222.3 | ||||||||||||||
Other | 14.0 | 0.3 | 0.3 | 0.2 | 0.2 | 3.5 | 18.5 | ||||||||||||||
$ | 88.5 | $ | 236.5 | $ | 181.7 | $ | 60.1 | $ | 186.2 | $ | 320.3 | $ | 1,073.3 |
(1) | The debt repayment includes foreign denominated fixed rate debt translated using the year end exchange rate and excludes related foreign exchange risk management contracts. |
(2) | Interest payments are calculated at fixed rate debt interest rates and December 31, 2017 period end exchange rate. |
(3) | Includes office rent and other commitments. |
PENGROWTH 2017 Financial Results | 42 |
20. | CONTINGENCIES |
21. | SUPPLEMENTARY DISCLOSURES |
Year ended December 31 | ||||||
2017 | 2016 | |||||
Operating | $ | 30.1 | $ | 44.1 | ||
General and administrative | 35.5 | 50.2 | ||||
Total employee compensation costs | $ | 65.6 | $ | 94.3 |
Year ended December 31, 2017 | Wages & benefits paid | Bonus and other compensation paid | Share based compensation expense | Severance paid | Total | ||||||||||
Directors | $ | 0.6 | $ | — | $ | (0.6 | ) | $ | — | $ | — | ||||
Officers | 2.2 | 2.7 | 1.9 | — | 6.8 | ||||||||||
$ | 2.8 | $ | 2.7 | $ | 1.3 | $ | — | $ | 6.8 | ||||||
Year ended December 31, 2016 | Wages & benefits paid | Bonus and other compensation paid | Share based compensation expense | Severance paid | Total | ||||||||||
Directors | $ | 0.6 | $ | — | $ | 2.3 | $ | — | $ | 2.9 | |||||
Officers | 2.8 | 0.7 | 5.3 | 0.6 | 9.4 | ||||||||||
$ | 3.4 | $ | 0.7 | $ | 7.6 | $ | 0.6 | $ | 12.3 |
PENGROWTH 2017 Financial Results | 43 |
(millions of dollars) | 2017 | 2016 | ||||
Property acquisition costs | ||||||
- Proved | $ | 0.1 | $ | 1.3 | ||
- Unproved | — | — | ||||
Exploration costs | (0.3 | ) | 0.3 | |||
Development costs | (289.9 | ) | 20.2 | |||
Injectants costs | — | 0.4 | ||||
$ | (290.1 | ) | $ | 22.2 | ||
(millions of dollars) | 2017 | 2016 | ||||
Oil and natural gas assets | $ | 1,097.4 | $ | 2,956.1 | ||
Add: Exploration and evaluation assets | 232.0 | 496.3 | ||||
$ | 1,329.4 | $ | 3,452.4 | |||
Unproved oil and gas properties | ||||||
Unproven properties included in oil and natural gas assets | $ | 154.9 | $ | 864.9 | ||
Exploration and evaluation assets | 232.0 | 496.3 | ||||
$ | 386.9 | $ | 1,361.2 | |||
Proved oil & gas properties | 942.5 | 2,091.2 | ||||
Total capitalized costs | $ | 1,329.4 | $ | 3,452.4 | ||
Net Proved Developed and Undeveloped Reserves After Royalties | Crude Oil | Bitumen | NGLs | Natural Gas | ||||||||
MMbbls | MMbbls | MMbbls | Bcf | |||||||||
End of year 2015 | 39.7 | 95.3 | 10.7 | 331.4 | ||||||||
Revisions of previous estimates (including infill drilling & improved recovery) | (1.2 | ) | 16.0 | a | 5.0 | b | 21.7 | b | ||||
Purchase of reserves in place | — | — | — | — | ||||||||
Sale of reserves in place | (4.3 | ) | — | (0.1 | ) | (6.6 | ) | |||||
Discoveries and extensions | — | 36.1 | c | 0.9 | 8.0 | |||||||
Production | (3.9 | ) | (5.5 | ) | (2.3 | ) | (42.7 | ) | ||||
End of Year 2016 | 30.3 | 141.9 | 14.2 | 311.8 | ||||||||
Revisions of previous estimates (including infill drilling & improved recovery) | 0.2 | 1.9 | d | 0.2 | 9.9 | e | ||||||
Purchase of reserves in place | — | — | — | 4.5 | f | |||||||
Sale of reserves in place | (26.4 | ) | g | — | (12.7 | ) | g | (179.1 | ) | g | ||
Discoveries and extensions | — | 5.4 | h | — | 28.6 | i | ||||||
Production | (2.5 | ) | (5.0 | ) | (1.7 | ) | (33.4 | ) | ||||
End of Year 2017 | 1.6 | 144.2 | — | 142.3 | ||||||||
Notes Re Significant Changes: | ||||||||||||
(a) Primarily due to lower royalties for the Lindbergh oil sands development resulting from the lower constant bitumen price used in the reserve evaluation at December 31, 2016 and improved performance. | ||||||||||||
(b) Due to improved performance and infill drilling in various properties. | ||||||||||||
(c) Primarily due to reserves associated with regulatory approval of Lindbergh oil sands Phase 2 expansion. | ||||||||||||
(d) Primarily due to infill drilling and technical revisions due to digitized mapping at Lindbergh. | ||||||||||||
(e) Primarily due to improved constant pricing resulting in recovery of late life reserves. | ||||||||||||
(f) Acquisition of a small partner working interest in the Groundbirch area resulting in an increase of Total Proved Plus Probable Reserves. | ||||||||||||
(g) Primarily due to our non-core asset disposition program as described under "Acquisitions and Divestitures" on page 26 of Pengrowth's Annual Information Form, to our Form 40-F dated February 28, 2018. | ||||||||||||
(h) Proved reserve additions booked in Lindbergh for a previously cyclic steam stimulated ("CSS") area as described under the "Statement of Oil and Gas Reserves and Reserves data" on page 23 of Pengrowth's Annual Information Form, to our Form 40-F dated February 28, 2018. | ||||||||||||
(i) Proved Reserves booked at Groundbirch due to offsetting competitor activity. | ||||||||||||
Net Proved Developed and Undeveloped Reserves After Royalties | Crude Oil | Bitumen | NGLs | Natural Gas | ||||||||
MMbbls | MMbbls | MMbbls | Bcf | |||||||||
Net Proved Developed Reserves After Royalty | ||||||||||||
End of year 2015 | 33.4 | 16.5 | 10.3 | 242.4 | ||||||||
End of year 2016 | 26.5 | 13.9 | 11.7 | 207.6 | ||||||||
End of year 2017 | 1.6 | 22.4 | — | 31.2 | ||||||||
Net Proved Undeveloped Reserves After Royalty | ||||||||||||
End of year 2015 | 6.3 | 78.8 | 0.4 | 89.0 | ||||||||
End of year 2016 | 3.8 | 128.0 | 2.5 | 104.2 | ||||||||
End of year 2017 | — | 121.8 | — | 111.1 |
1. | Net after royalty reserves are Pengrowth’s lessor royalty, overriding royalty, and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Crown royalties are subject to change by legislation or regulation and vary depending on production rates, selling prices and potential 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 the average of the commodity prices on the first day of each month for the years ended December 31, 2017 and 2016. |
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. |
(millions of dollars) | 2017 | 2016 | ||||
Future cash inflows | $ | 6,838 | $ | 6,801 | ||
Future costs | ||||||
- Future production costs | (3,388 | ) | (4,227 | ) | ||
- Future developments costs | (1,919 | ) | (1,464 | ) | ||
- Future income taxes | (12 | ) | — | |||
Future net cash flows | $ | 1,519 | $ | 1,110 | ||
Deduct: 10% annual discount factor | (777 | ) | (569 | ) | ||
Standardized measure of discounted future net cash flows | $ | 742 | $ | 541 | ||
(millions of dollars) | 2017 | 2016 | ||||
Future discounted net cash flow at beginning of year | $ | 541 | $ | 713 | ||
Sales and transfers of oil and gas, net of production costs, produced during the period | (199 | ) | (599 | ) | ||
Net change in sales & transfer prices related to future production | 484 | (474 | ) | |||
Previously estimated development costs incurred during the period | 117 | 63 | ||||
Changes in estimated future development costs | (158 | ) | (92 | ) | ||
Net change due to extensions, discoveries, and improved recovery | 45 | 87 | ||||
Change due to revisions (including infill drilling & improved recovery) | 17 | 53 | ||||
Accretion of discount | 54 | 71 | ||||
Acquisition of reserves | 3 | — | ||||
Sales of reserves in place | (156 | ) | (20 | ) | ||
Net change in income taxes | (4 | ) | — | |||
Other - unspecified | (2 | ) | 739 | |||
Future discounted net cash flow at end of year | $ | 742 | $ | 541 | ||
1. | The schedules above are calculated using year-end costs, statutory tax rates and proved oil and gas reserves and the average of the commodity prices on the first day of each month for the years ended December 31, 2017 and 2016. 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 because they are not individually significant. |
Development | Exploration | Total | ||||||||||||
Wells | Gross | Net | Gross | Net | Gross | Net | ||||||||
Natural Gas | 5.0 | 4.0 | — | — | 5.0 | 4.0 | ||||||||
Crude Oil | — | — | — | — | — | — | ||||||||
Bitumen | 12.0 | 12.0 | — | — | 12.0 | 12.0 | ||||||||
Service | 10.0 | 10.0 | — | — | 10.0 | 10.0 | ||||||||
Stratigraphic Test | 2.0 | 2.0 | — | — | 2.0 | 2.0 | ||||||||
Dry | — | — | — | — | — | — | ||||||||
Total | 29.0 | 28.0 | — | — | 29.0 | 28.0 |
Development | Exploration | Total | ||||||||||||
Wells | Gross | Net | Gross | Net | Gross | Net | ||||||||
Natural Gas | 1.0 | 0.2 | — | — | 1.0 | 0.2 | ||||||||
Crude Oil | — | — | — | — | — | — | ||||||||
Bitumen | — | — | — | — | — | — | ||||||||
Service | — | — | — | — | — | — | ||||||||
Stratigraphic Test | — | — | — | — | — | — | ||||||||
Dry | — | — | — | — | — | — | ||||||||
Total | 1.0 | 0.2 | — | — | 1.0 | 0.2 |
Development | Exploration | Total | ||||||||||||
Wells | Gross | Net | Gross | Net | Gross | Net | ||||||||
Natural Gas | 2.0 | 1.4 | — | — | 2.0 | 1.4 | ||||||||
Crude Oil | 7.0 | 5.4 | 1.0 | 0.3 | 8.0 | 5.7 | ||||||||
Bitumen | — | — | — | — | — | — | ||||||||
Service | — | — | — | — | — | — | ||||||||
Stratigraphic Test | — | — | — | — | — | — | ||||||||
Dry | — | — | — | — | — | — | ||||||||
Total | 9.0 | 6.8 | 1.0 | 0.3 | 10.0 | 7.1 |
Producing | Non-Producing | Total | ||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||
Crude Oil Wells | ||||||||||||||
Alberta | 48 | 18 | 79 | 47 | 127 | 65 | ||||||||
British Columbia | 60 | 33 | 179 | 114 | 239 | 147 | ||||||||
Saskatchewan | 62 | 2 | 28 | 6 | 90 | 8 | ||||||||
Bitumen Wells | ||||||||||||||
Alberta | 30 | 30 | 6 | 1 | 36 | 31 | ||||||||
Natural Gas Wells | ||||||||||||||
Alberta | 252 | 93 | 81 | 44 | 333 | 137 | ||||||||
British Columbia | 122 | 60 | 222 | 126 | 344 | 187 | ||||||||
Saskatchewan | 1 | 1 | 10 | 2 | 11 | 3 | ||||||||
Nova Scotia | 19 | 2 | 2 | — | 21 | 2 | ||||||||
Service Wells (1) | ||||||||||||||
Alberta | — | — | 132 | 81 | 132 | 81 | ||||||||
British Columbia | — | — | 183 | 121 | 183 | 121 | ||||||||
Saskatchewan | — | — | 347 | 24 | 347 | 24 | ||||||||
Other (2) | ||||||||||||||
Alberta | — | — | 9 | 7 | 9 | 7 | ||||||||
British Columbia | — | — | 4 | 4 | 4 | 4 | ||||||||
Saskatchewan | — | — | — | — | — | — | ||||||||
Total | 594 | 239 | 1,282 | 577 | 1,876 | 817 |
(2) | Other includes standing, zonally abandoned and suspended wellbores with undefined zones. |
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Derek W. Evans | ||||
Name: Derek W. Evans | ||||
Title: President and Chief Executive Officer | ||||
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and | |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Christopher G. Webster | ||||
Name: Christopher G. Webster | ||||
Title: Chief Financial Officer |
1. | I have reviewed this annual report on Form 40-F of Pengrowth Energy Corporation; | |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; | |
4. | The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
(c) | Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
(d) | Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and |
5. | The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and | ||
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting. |
/s/ Derek W. Evans | ||||
Name: Derek W. Evans | ||||
Title: President and Chief Executive Officer | ||||
1. | I have reviewed this annual report on Form 40-F of Pengrowth Energy Corporation; | |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; | |
4. | The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||||
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||||
(c) | Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||||
(d) | Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and | ||||
5. | The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and | ||
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting. |
/s/ Christopher G. Webster | ||||
Name: Christopher G. Webster | ||||
Title: Chief Financial Officer |
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