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2015 Annual Information Form – ARC Resources Ltd. | Page 1 |
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APPENDIX A | - | |
APPENDIX B | - | |
APPENDIX C | - | |
APPENDIX D | - |
2015 Annual Information Form – ARC Resources Ltd. | Page 2 |
2015 Annual Information Form – ARC Resources Ltd. | Page 3 |
2015 Annual Information Form – ARC Resources Ltd. | Page 4 |
Oil and Natural Gas Liquids | |
bbl | barrel |
Mbbl | thousand barrels |
MMbbl | million barrels |
bbl/d | barrels per day |
NGLs | natural gas liquids |
Natural Gas | |
Mcf | thousand cubic feet |
Mcf/d | thousand cubic feet per day |
MMcf | million cubic feet |
MMcf/d | million cubic feet per day |
Bcf | billion cubic feet |
Bcfe | billion cubic feet equivalent |
Tcf | trillion cubic feet |
MMbtu | million British thermal units |
Other | |
API | Indication of specific gravity of crude oil measured on the API gravity scale |
boe | barrels of oil equivalent |
boe/d | barrels of oil equivalent per day |
GJ | gigajoules |
Mboe | thousand barrels of oil equivalent |
$MM | million dollars |
2015 Annual Information Form – ARC Resources Ltd. | Page 5 |
To Convert From | To | Multiply By |
cubic metres | cubic feet | 35.315 |
barrels | cubic metres | 0.159 |
cubic metres | barrels | 6.290 |
feet | metres | 0.305 |
metres | feet | 3.281 |
miles | kilometres | 1.609 |
kilometres | miles | 0.621 |
acres | hectares | 0.4047 |
hectares | acres | 2.471 |
2015 Annual Information Form – ARC Resources Ltd. | Page 6 |
2015 Annual Information Form – ARC Resources Ltd. | Page 7 |
2015 Annual Information Form – ARC Resources Ltd. | Page 9 |
2015 Annual Information Form – ARC Resources Ltd. | Page 10 |
Company Gross Reserves | Light Crude Oil and Medium Crude Oil (Mbbl) | Heavy Crude Oil (Mbbl) | Tight Oil (Mbbl) | Total Oil (Mbbl) | Conven-tional Natural Gas (Bcf) | Shale Gas (Bcf) | Coal Bed Methane (Bcf) | Total Gas (Bcf) | NGLs (Mbbl) (1) | Total Oil Equivalent (Mboe) | ||||||||||||||||||||||||||||||
PROVED | ||||||||||||||||||||||||||||||||||||||||
Developed Producing | 66,813 | 1,252 | 14,098 | 82,163 | 67.7 | 686.9 | 5.2 | 759.8 | 12,712 | 221,509 | ||||||||||||||||||||||||||||||
Developed Non-Producing | 954 | - | 1,959 | 2,913 | 0.5 | 49.2 | - | 49.7 | 870 | 12,062 | ||||||||||||||||||||||||||||||
Undeveloped | 5,988 | 84 | 7,712 | 13,784 | 5.1 | 776.7 | 1.1 | 783.0 | 15,470 | 159,755 | ||||||||||||||||||||||||||||||
TOTAL PROVED | 73,755 | 1,336 | 23,769 | 98,860 | 73.3 | 1,512.9 | 6.3 | 1,592.5 | 29,052 | 393,327 | ||||||||||||||||||||||||||||||
Probable | 29,661 | 428 | 17,535 | 47,623 | 28.7 | 1,297.8 | 3.1 | 1,329.7 | 24,292 | 293,524 | ||||||||||||||||||||||||||||||
TOTAL PROVED + PROBABLE | 103,416 | 1,764 | 41,303 | 146,483 | 102.0 | 2,810.7 | 9.4 | 2,922.1 | 53,343 | 686,851 |
Company Net Reserves | Light Crude Oil and Medium Crude Oil (Mbbl) | Heavy Crude Oil (Mbbl) | Tight Oil (Mbbl) | Total Oil (Mbbl) | Conven-tional Natural Gas (Bcf) | Shale Gas (Bcf) | Coal Bed Methane (Bcf) | Total Gas (Bcf) | NGLs (Mbbl) (1) | Total Oil Equivalent (Mboe) | ||||||||||||||||||||||||||||||
PROVED | ||||||||||||||||||||||||||||||||||||||||
Developed Producing | 60,287 | 1,695 | 12,612 | 74,594 | 62.3 | 580.0 | 4.8 | 647.1 | 9,689 | 192,131 | ||||||||||||||||||||||||||||||
Developed Non-Producing | 841 | - | 1,691 | 2,532 | 0.4 | 41.2 | - | 41.7 | 689 | 10,169 | ||||||||||||||||||||||||||||||
Undeveloped | 5,446 | 76 | 6,670 | 12,191 | 4.8 | 656.6 | 1.1 | 662.4 | 13,082 | 135,669 | ||||||||||||||||||||||||||||||
TOTAL PROVED | 66,574 | 1,771 | 20,972 | 89,317 | 67.5 | 1,277.8 | 5.9 | 1,351.1 | 23,460 | 337,969 | ||||||||||||||||||||||||||||||
Probable | 25,880 | 555 | 14,979 | 41,413 | 26.5 | 1,054.3 | 2.9 | 1,083.7 | 19,530 | 241,555 | ||||||||||||||||||||||||||||||
TOTAL PROVED + PROBABLE | 92,454 | 2,326 | 35,951 | 130,730 | 94.0 | 2,332.1 | 8.8 | 2,434.8 | 42,990 | 579,524 |
1) | Natural Gas Liquids includes Associated Natural Gas Liquids for both Conventional and Shale/Tight Reservoirs. |
Before-Tax ($ millions) | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% | |||||||||||||||
PROVED | ||||||||||||||||||||
Developed Producing | 4,670 | 3,289 | 2,533 | 2,064 | 1,748 | |||||||||||||||
Developed Non-Producing | 206 | 158 | 128 | 107 | 92 | |||||||||||||||
Undeveloped | 2,119 | 1,185 | 707 | 434 | 266 | |||||||||||||||
TOTAL PROVED | 6,995 | 4,632 | 3,367 | 2,605 | 2,106 | |||||||||||||||
Probable | 6,199 | 3,046 | 1,772 | 1,142 | 785 | |||||||||||||||
TOTAL PROVED + PROBABLE | 13,194 | 7,678 | 5,139 | 3,748 | 2,891 | |||||||||||||||
After-Tax (1)(2) ($ millions) | ||||||||||||||||||||
PROVED | ||||||||||||||||||||
Developed Producing | 4,030 | 2,906 | 2,279 | 1,885 | 1,615 | |||||||||||||||
Developed Non-Producing | 151 | 116 | 94 | 79 | 68 | |||||||||||||||
Undeveloped | 1,550 | 836 | 468 | 258 | 129 | |||||||||||||||
TOTAL PROVED | 5,732 | 3,858 | 2,841 | 2,222 | 1,812 | |||||||||||||||
Probable | 4,538 | 2,206 | 1,258 | 789 | 524 | |||||||||||||||
TOTAL PROVED + PROBABLE | 10,269 | 6,063 | 4,098 | 3,011 | 2,336 |
1) | Based on ARC’s estimated tax pools at year-end 2015. |
2) | The after-tax net present value of ARC's oil and gas properties presented here reflect the income tax burden on the properties on a stand-alone basis. It does not consider the business-entity-level tax situation, or tax planning. It does not provide an estimate of the net present value at the level of the business entity, which may be significantly different. ARC's audited consolidated financial statements for the year ended December 31, 2015 and the related Management's Discussion and Analysis should be consulted for information at the business entity level. |
2015 Annual Information Form – ARC Resources Ltd. | Page 12 |
Reserves Category ($ millions) | Revenue | Royalties | Operating Costs | Development Costs | Abandonment and Reclamation Costs (1) | Future Net Revenue Before Income Taxes | Income Taxes | Future Net Revenue After Income Taxes | ||||||||||||||||||||||||
Proved Reserves | 16,829 | 2,160 | 5,765 | 1,488 | 421 | 6,995 | 1,264 | 5,732 | ||||||||||||||||||||||||
Proved Plus Probable Reserves | 30,145 | 4,210 | 9,484 | 2,730 | 527 | 13,194 | 2,925 | 10,269 |
1) | Estimated future well abandonment and reclamation costs related to reserves wells have been taken into account by GLJ in determining the aggregate future net revenue therefrom. |
Reserves Category | Production Group | Future Net Revenue Before Income Taxes (Discounted at 10% per Year) ($ millions) | Per Unit (1) | |||
Proved Reserves | Light Crude Oil and Medium Crude Oil (2) | 1,209 | $16.08/boe | |||
Heavy Crude Oil (2)(3) | 31 | $17.30/boe | ||||
Tight Oil | 542 | $15.46/boe | ||||
Conventional Natural Gas (4) | 23 | $0.73/Mcfe | ||||
Shale Gas | 1,561 | $1.18/Mcfe | ||||
Coal Bed Methane | 2 | $0.34/Mcfe | ||||
Total | 3,367 | $9.96/boe | ||||
Proved + Probable Reserves | Light Crude Oil and Medium Crude Oil (2) | 1,557 | $14.83/boe | |||
Heavy Crude Oil (2)(3) | 40 | $17.20/boe | ||||
Tight Oil | 937 | $13.99/boe | ||||
Conventional Natural Gas (4) | 30 | $0.75/Mcfe | ||||
Shale Gas | 2,570 | $1.08/Mcfe | ||||
Coal Bed Methane | 4 | $0.46/Mcfe | ||||
Total | 5,139 | $8.87/boe |
1) | Unit values are based on Net Reserves. |
2) | Including solution gas and other by-products. |
3) | Per unit revenue positively impacted by a portion of value coming from royalty interest reserves. |
4) | Including by-products but excluding solution gas and by-products from oil wells. |
2015 Annual Information Form – ARC Resources Ltd. | Page 13 |
Oil | Natural Gas | Edmonton Liquids Prices | ||||||||||||||||||||||||||||||||||||||
WTI Cushing Oklahoma (US$/bbl) | Edmonton Par Price 40° API (Cdn$/bbl) | Hardisty Heavy 12° API (Cdn$/bbl) | Cromer Medium 29.3° API (Cdn$/bbl) | AECO Gas Price (Cdn$/ MMbtu) | Propane (Cdn$/bbl) | Butane (Cdn$/bbl) | Pentanes Plus (Cdn$/bbl) | Inflation Rate (1) (%/Year) | Exchange Rate (2) (US$/Cdn$) | |||||||||||||||||||||||||||||||
Forecast | ||||||||||||||||||||||||||||||||||||||||
2016 | 44.00 | 55.86 | 35.70 | 50.80 | 2.76 | 9.58 | 41.90 | 60.79 | 2.0 | 0.725 | ||||||||||||||||||||||||||||||
2017 | 52.00 | 64.00 | 45.02 | 59.52 | 3.27 | 16.00 | 48.00 | 68.48 | 2.0 | 0.750 | ||||||||||||||||||||||||||||||
2018 | 58.00 | 68.39 | 49.06 | 63.60 | 3.45 | 20.52 | 51.29 | 73.17 | 2.0 | 0.775 | ||||||||||||||||||||||||||||||
2019 | 64.00 | 73.75 | 54.42 | 68.59 | 3.63 | 25.81 | 55.31 | 78.91 | 2.0 | 0.800 | ||||||||||||||||||||||||||||||
2020 | 70.00 | 78.79 | 59.75 | 73.27 | 3.81 | 27.58 | 59.09 | 84.30 | 2.0 | 0.825 | ||||||||||||||||||||||||||||||
2021 | 75.00 | 82.35 | 63.56 | 76.59 | 3.90 | 28.82 | 61.76 | 88.12 | 2.0 | 0.850 | ||||||||||||||||||||||||||||||
2022 | 80.00 | 88.24 | 69.32 | 82.06 | 4.10 | 30.88 | 66.18 | 94.41 | 2.0 | 0.850 | ||||||||||||||||||||||||||||||
2023 | 85.00 | 94.12 | 74.62 | 87.53 | 4.30 | 32.94 | 70.59 | 100.71 | 2.0 | 0.850 | ||||||||||||||||||||||||||||||
2024 | 87.88 | 96.48 | 78.40 | 89.73 | 4.50 | 33.77 | 72.36 | 103.24 | 2.0 | 0.850 | ||||||||||||||||||||||||||||||
2025 | 89.63 | 98.41 | 79.99 | 91.52 | 4.60 | 34.44 | 73.81 | 105.30 | 2.0 | 0.850 | ||||||||||||||||||||||||||||||
Thereafter | (3) | (3) | (3) | (3) | (3) | (3) | (3) | (3) | 2.0 | 0.850 |
1) | Inflation rates for forecasting costs. |
2) | Exchange rates used to generate the benchmark reference prices in this table. |
3) | Prices escalate two per cent per year from 2025. |
1. | "Gross" means: |
a) | in relation to our interest in production and reserves, our interest (operating and non-operating) before deduction of royalties and without including any royalty interest to us; |
b) | in relation to wells, the total number of wells in which we have an interest; and |
c) | in relation to properties, the total area of properties in which we have an interest. |
2. | "Net" means: |
a) | in relation to our interest in production and reserves, our interest (operating and non-operating) after deduction of royalty obligations, plus our royalty interest in production or reserves; |
b) | in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and |
c) | in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest we owned. |
3. | Columns may not add due to rounding. |
4. | The forecast price and cost assumptions assumed the continuance of current laws and regulations. |
5. | All factual data supplied to GLJ was accepted as represented. No field inspection was conducted. |
2015 Annual Information Form – ARC Resources Ltd. | Page 14 |
6. | The crude oil, natural gas liquids and natural gas reserves estimates presented in the GLJ Report are based on the definitions and guidelines contained in the CSA Notice 51-324 – Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities and the COGE Handbook. A summary of those definitions are set forth below. |
a) | Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
b) | Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
a) | Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. |
i) | Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. |
ii) | Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. |
b) | Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned. |
a) | at least a 90 per cent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and |
2015 Annual Information Form – ARC Resources Ltd. | Page 15 |
b) | at least a 50 per cent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. |
Light Crude Oil and Medium Crude Oil (Mbbl) | Heavy Crude Oil (Mbbl) | Tight Oil (Mbbl) | Total Oil (Mbbl) | Conven-tional Natural Gas (Bcf) | Shale Gas (Bcf) | Coal Bed Methane (Bcf) | Total Gas (Bcf) | NGLs (Mbbl) (1) | Total Oil Equivalent 2015 (Mboe) | |||||||||||||||||||||||||||||||
PROVED | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | 103,379 | 1,552 | - | 104,931 | 1,523.9 | - | 8.9 | 1,532.8 | 21,668 | 382,063 | ||||||||||||||||||||||||||||||
Product Type Transfer (2) | (17,395 | ) | - | 17,395 | - | (1,379.1 | ) | 1,379.1 | - | - | - | - | ||||||||||||||||||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Extensions and Improved Recovery (3) | 858 | - | 6,651 | 7,509 | 0.8 | 190.2 | - | 191.0 | 4,286 | 43,630 | ||||||||||||||||||||||||||||||
Technical Revisions | 5,552 | 415 | 3,318 | 9,284 | 34.5 | 94.1 | (0.3 | ) | 128.3 | 6,704 | 37,366 | |||||||||||||||||||||||||||||
Acquisitions | 63 | - | - | 63 | - | - | - | - | - | 63 | ||||||||||||||||||||||||||||||
Dispositions | (4,654 | ) | (70 | ) | - | (4,724 | ) | (56.0 | ) | - | - | (56.0 | ) | (260 | ) | (14,312 | ) | |||||||||||||||||||||||
Economic Factors | (5,945 | ) | (406 | ) | (121 | ) | (6,472 | ) | (36.9 | ) | (3.5 | ) | (1.2 | ) | (41.6 | ) | (705 | ) | (14,113 | ) | ||||||||||||||||||||
Production | (8,103 | ) | (155 | ) | (3,474 | ) | (11,731 | ) | (13.8 | ) | (147.1 | ) | (1.1 | ) | (162.0 | ) | (2,642 | ) | (41,372 | ) | ||||||||||||||||||||
December 31, 2015 | 73,755 | 1,336 | 23,769 | 98,860 | 73.3 | 1,512.9 | 6.3 | 1,592.5 | 29,052 | 393,327 | ||||||||||||||||||||||||||||||
PROBABLE | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | 46,624 | 481 | - | 47,105 | 1,344.6 | - | 4.1 | 1,348.8 | 18,786 | 290,684 | ||||||||||||||||||||||||||||||
Product Type Transfer (2) | (14,210 | ) | - | 14,210 | - | (1,280.2 | ) | 1,280.2 | - | - | - | - | ||||||||||||||||||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Extensions and Improved Recovery (3) | 1,101 | - | 3,561 | 4,662 | 0.9 | 28.6 | - | 29.5 | 4,780 | 14,360 | ||||||||||||||||||||||||||||||
Technical Revisions | (911 | ) | 19 | 224 | (669 | ) | (9.0 | ) | (2.4 | ) | (0.3 | ) | (11.7 | ) | 1,199 | (1,422 | ) | |||||||||||||||||||||||
Acquisitions | 17 | - | - | 17 | - | - | - | - | - | 17 | ||||||||||||||||||||||||||||||
Dispositions | (4,063 | ) | (19 | ) | - | (4,082 | ) | (26.4 | ) | - | - | (26.4 | ) | (506 | ) | (8,992 | ) | |||||||||||||||||||||||
Economic Factors | 1,103 | (53 | ) | (460 | ) | 590 | (1.3 | ) | (8.5 | ) | (0.7 | ) | (10.5 | ) | 33 | (1,123 | ) | |||||||||||||||||||||||
Production | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
December 31, 2015 | 29,661 | 428 | 17,535 | 47,623 | 28.7 | 1,297.8 | 3.1 | 1,329.7 | 24,292 | 293,524 | ||||||||||||||||||||||||||||||
PROVED PLUS PROBABLE | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | 150,003 | 2,032 | - | 152,035 | 2,868.5 | - | 13.0 | 2,881.6 | 40,454 | 672,748 | ||||||||||||||||||||||||||||||
Product Type Transfer (2) | (31,604 | ) | - | 31,604 | - | (2,659.3 | ) | 2,659.3 | - | - | - | - | ||||||||||||||||||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Extensions and Improved Recovery (3) | 1,959 | - | 10,212 | 12,171 | 1.7 | 218.8 | - | 220.5 | 9,066 | 57,990 | ||||||||||||||||||||||||||||||
Technical Revisions | 4,640 | 433 | 3,542 | 8,616 | 25.5 | 91.6 | (0.6 | ) | 116.6 | 7,903 | 35,943 | |||||||||||||||||||||||||||||
Acquisitions | 80 | - | - | 80 | - | - | - | - | - | 80 | ||||||||||||||||||||||||||||||
Dispositions | (8,717 | ) | (88 | ) | - | (8,806 | ) | (82.4 | ) | - | - | (82.4 | ) | (766 | ) | (23,303 | ) | |||||||||||||||||||||||
Economic Factors | (4,842 | ) | (459 | ) | (581 | ) | (5,882 | ) | (38.2 | ) | (12.0 | ) | (1.9 | ) | (52.1 | ) | (672 | ) | (15,236 | ) | ||||||||||||||||||||
Production | (8,103 | ) | (155 | ) | (3,474 | ) | (11,731 | ) | (13.8 | ) | (147.1 | ) | (1.1 | ) | (162.0 | ) | (2,642 | ) | (41,372 | ) | ||||||||||||||||||||
December 31, 2015 | 103,416 | 1,764 | 41,303 | 146,483 | 102.0 | 2,810.7 | 9.4 | 2,922.1 | 53,343 | 686,851 |
1) | Natural Gas Liquids includes Associated Natural Gas Liquids for both Conventional and Shale/Tight Reservoirs. |
2) | Effective July 1, 2015 a number of amendments were made to NI 51-101, including amendments relating to the disclosure of different product types. In order to assist readers in their review of the reconciliation of our reserves between year-end 2014 and year-end 2015, we have provided information regarding "Product Type Transfer" which illustrates reserve volumes for product types at year-end 2014 which would have been classified as a different product type had the amendments to NI 51-101 been effective at December 31, 2014. |
3) | Reserve additions for Infill Drilling, Extensions and Improved Recovery are combined and reported as ‘Extensions and Improved Recovery’. |
2015 Annual Information Form – ARC Resources Ltd. | Page 17 |
Year | Proved Reserves ($ millions) | Proved Plus Probable Reserves ($ millions) | ||||||
2016 | 215.4 | 465.4 | ||||||
2017 | 358.3 | 515.2 | ||||||
2018 | 384.9 | 602.7 | ||||||
2019 | 236.4 | 377.0 | ||||||
2020 | 83.1 | 147.9 | ||||||
Remainder | 210.0 | 622.3 | ||||||
Total: Undiscounted | 1,488.2 | 2,730.5 | ||||||
Total: Discounted at 10% per Year | 1,126.8 | 1,982.0 |
2015 Annual Information Form – ARC Resources Ltd. | Page 18 |
Light Crude Oil and Medium Crude Oil (Mbbl) | Heavy Crude Oil (Mbbl) | Tight Oil (Mbbl) | Conventional Natural Gas (Bcf) | Shale Gas (Bcf) | ||||||||||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||||
2013 | 4,534 | 10,773 | 105 | 105 | 2,474 | 6,917 | 8.6 | 8.7 | 13.9 | 774.8 | ||||||||||||||||||||||||||||||
2014 | 3,253 | 8,451 | - | 105 | 1,029 | 6,740 | 0.9 | 6.2 | 130.9 | 761.2 | ||||||||||||||||||||||||||||||
2015 | 507 | 5,988 | - | 84 | 3,008 | 7,712 | 0.5 | 5.1 | 166.8 | 776.7 | ||||||||||||||||||||||||||||||
Coal Bed Methane (Bcf) | Natural Gas Liquids (Mbbl) | Total (Mboe) | ||||||||||||||||||||||||||||||||||||||
First Attributed | Total at Year-End | First Attributed | Total at Year-End | First Attributed | Total at Year-End | |||||||||||||||||||||||||||||||||||
2013 | - | 1.9 | 860 | 9,462 | 11,727 | 158,139 | ||||||||||||||||||||||||||||||||||
2014 | NMF | 2.2 | 1,869 | 8,833 | 28,140 | 152,390 | ||||||||||||||||||||||||||||||||||
2015 | NMF | 1.2 | 3,795 | 15,470 | 35,205 | 159,755 |
Light Crude Oil and Medium Crude Oil (Mbbl) | Heavy Crude Oil (Mbbl) | Tight Oil (Mbbl) | Conventional Natural Gas (Bcf) | Shale Gas (Bcf) | ||||||||||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||||
2013 | 3,158 | 8,818 | - | 42 | 4,308 | 9,132 | 2.9 | 5.5 | 66.0 | 935.7 | ||||||||||||||||||||||||||||||
2014 | 3,240 | 7,994 | - | 42 | 1,715 | 11,605 | 1.1 | 5.7 | 219.6 | 1,052.9 | ||||||||||||||||||||||||||||||
2015 | 1,752 | 10,083 | - | 29 | 3,911 | 11,449 | 1.4 | 8.4 | 195.0 | 1,034.5 | ||||||||||||||||||||||||||||||
Coal Bed Methane (Bcf) | Natural Gas Liquids (Mbbl) | Total (Mboe) | ||||||||||||||||||||||||||||||||||||||
First Attributed | Total at Year-End | First Attributed | Total at Year-End | First Attributed | Total at Year-End | |||||||||||||||||||||||||||||||||||
2013 | - | 2.5 | 2,573 | 13,054 | 21,523 | 188,324 | ||||||||||||||||||||||||||||||||||
2014 | NMF | 2.6 | 3,723 | 13,837 | 45,467 | 210,357 | ||||||||||||||||||||||||||||||||||
2015 | NMF | 2.0 | 5,747 | 19,169 | 44,148 | 214,882 |
2015 Annual Information Form – ARC Resources Ltd. | Page 19 |
Abandonment & Reclamation Costs Escalated at 2.0% | Undiscounted ($ millions) | Discounted at 10% ($ millions) | ||||||
Total as at December 31, 2015 | 1,196.2 | 109.7 | ||||||
Anticipated to be paid in 2016 | 17.4 | 15.8 | ||||||
Anticipated to be paid in 2017 | 7.2 | 5.9 | ||||||
Anticipated to be paid in 2018 | 10.4 | 7.8 |
2015 Annual Information Form – ARC Resources Ltd. | Page 20 |
Light Crude Oil and Medium Crude Oil and Tight Oil (1) | Heavy Crude Oil (1) | Natural Gas (1)(2) | Natural Gas Liquids (1) | Total Oil Equivalent Production (1) | Proved Reserves | Proved Plus Probable Reserves | ||||||||||||||||||||||||||
Core Area | (bbl/d) | (bbl/d) | (MMcf/d) | (bbl/d) | (boe/d) | (Mboe) | (Mboe) | (%) | ||||||||||||||||||||||||
NE British Columbia | 3,406 | - | 350.8 | 4,147 | 66,015 | 270,266 | 503,541 | 73.3 | ||||||||||||||||||||||||
Northern Alberta | 7,477 | 8 | 68.2 | 2,107 | 20,963 | 41,315 | 68,028 | 9.9 | ||||||||||||||||||||||||
Pembina | 7,567 | 126 | 12.4 | 615 | 10,370 | 34,823 | 51,963 | 7.6 | ||||||||||||||||||||||||
SE Saskatchewan & Manitoba (3) | 9,570 | - | 1.1 | 139 | 9,884 | 27,096 | 37,824 | 5.5 | ||||||||||||||||||||||||
South Central Alberta | 3,685 | 297 | 11.3 | 225 | 6,091 | 19,828 | 25,496 | 3.7 | ||||||||||||||||||||||||
Total | 31,705 | 431 | 443.8 | 7,233 | 113,323 | 393,327 | 686,851 | 100.0 |
1) | Production volumes as disclosed above are "gross production" which is our interest (operated and non-operated) in production before deduction of royalties and without including any royalty interests to us. These volumes differ from the "company interest production" volumes disclosed in this Annual Information Form under "ARC Resources Ltd. - Development of our Business" and "Statement of Reserves Data and Other Oil and Gas Information – Production History" as well as in our audited consolidated financial statements for the year ended December 31, 2015 and the related Management’s Discussion and Analysis which is our interest (operated and non-operated) in production before deduction of royalties inclusive of royalty interests. |
2) | Natural Gas production includes production from Conventional Natural Gas, Shale Gas and Coal Bed Methane. |
2015 Annual Information Form – ARC Resources Ltd. | Page 21 |
3) | ARC divested its properties in Manitoba in the fourth quarter of 2015. |
2015 Annual Information Form – ARC Resources Ltd. | Page 22 |
2015 Annual Information Form – ARC Resources Ltd. | Page 23 |
By Core Area | Oil Wells (1) | Natural Gas Wells (2) | ||||||||||||||||||||||||||||||
Producing | Non-Producing | Producing | Non-Producing | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
NE British Columbia | 66 | 65 | 28 | 27 | 343 | 315 | 101 | 90 | ||||||||||||||||||||||||
Northern Alberta | 845 | 396 | 409 | 134 | 454 | 107 | 159 | 60 | ||||||||||||||||||||||||
Pembina | 1,209 | 685 | 386 | 160 | 50 | 11 | 21 | 4 | ||||||||||||||||||||||||
South Central Alberta | 513 | 500 | 89 | 85 | 535 | 173 | 103 | 16 | ||||||||||||||||||||||||
SE Saskatchewan & Manitoba (3) | 1,636 | 669 | 407 | 148 | - | - | - | - | ||||||||||||||||||||||||
Total | 4,269 | 2,316 | 1,319 | 554 | 1,382 | 607 | 384 | 171 |
By Province | Oil Wells (1) | Natural Gas Wells (2) | ||||||||||||||||||||||||||||||
Producing | Non-Producing | Producing | Non-Producing | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
Alberta | 2,567 | 1,582 | 883 | 378 | 1,038 | 292 | 272 | 78 | ||||||||||||||||||||||||
British Columbia | 66 | 65 | 28 | 27 | 343 | 314 | 101 | 90 | ||||||||||||||||||||||||
Saskatchewan | 1,636 | 668 | 408 | 149 | 1 | 0.3 | 11 | 3 | ||||||||||||||||||||||||
Total (3) | 4,269 | 2,316 | 1,319 | 554 | 1,382 | 607 | 384 | 171 |
1) | Includes light crude oil and medium crude oil wells, heavy crude oil wells and tight oil wells. |
2) | Includes conventional natural gas wells, shale gas wells and coalbed methane wells. |
3) | Does not include any wells in Manitoba as ARC divested its properties in Manitoba in the fourth quarter of 2015. |
2015 Annual Information Form – ARC Resources Ltd. | Page 24 |
Gross | Net | |||||||
NE British Columbia | 147,787 | 133,194 | ||||||
Northern Alberta | 199,643 | 142,124 | ||||||
Pembina | 39,424 | 5,365 | ||||||
South Central Alberta | 14,454 | 9,584 | ||||||
SE Saskatchewan & Manitoba (1) | 27,655 | 22,307 | ||||||
Total | 428,963 | 312,574 |
1) | Does not include any lands in Manitoba as ARC divested its properties in Manitoba in the fourth quarter of 2015. |
Abandonment & Reclamation Costs Escalated at 2.0% | Undiscounted ($ millions) | Discounted at 10% ($ millions) | ||||||
Total as at December 31, 2015 | 19.0 | 5.7 | ||||||
Anticipated to be paid in 2016 | 1.0 | 0.9 | ||||||
Anticipated to be paid in 2017 | 0.5 | 0.4 | ||||||
Anticipated to be paid in 2018 | 0.4 | 0.3 |
2015 Annual Information Form – ARC Resources Ltd. | Page 25 |
($ millions) | NE British Columbia | Northern Alberta | Pembina | South Central Alberta | SE Sask & Manitoba (1) | Corporate | Total | |||||||||||||||||||||
Property Acquisition (Disposition) Costs, Net (2) | ||||||||||||||||||||||||||||
Proved Properties | - | (7.6 | ) | - | (38.9 | ) | (42.3 | ) | - | (88.8 | ) | |||||||||||||||||
Undeveloped Properties | 14.1 | 0.3 | - | - | - | - | 14.4 | |||||||||||||||||||||
Exploration Costs (3) | 33.9 | - | - | - | - | - | 33.9 | |||||||||||||||||||||
Development Costs (4) | 367.3 | 65.3 | 28.7 | 14.7 | 25.3 | - | 501.3 | |||||||||||||||||||||
Corporate Capital Costs (5) | - | - | - | - | - | 13.1 | 13.1 | |||||||||||||||||||||
Total | 415.3 | 58.0 | 28.7 | (24.2 | ) | (17.0 | ) | 13.1 | 473.9 |
1) | ARC divested its properties in Manitoba in the fourth quarter of 2015. |
2) | Represents acquisition costs net of dispositions and property swaps. Acquisition value is net of post-closing adjustments. Disposition value represents proceeds and adjustments to proceeds from divestitures. |
3) | Represents asset additions that have been determined by Management to be in the exploration and evaluation stage and includes costs of land acquired ($1.5 million). |
4) | Represents additions to oil and gas development and production assets and administrative assets and includes costs of land acquired ($5.2 million). |
5) | Represents administrative assets allocated at the corporate level. |
2015 Annual Information Form – ARC Resources Ltd. | Page 26 |
By Core Area | Development Wells (1) | Total (1) | ||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
NE British Columbia | 49.0 | 49.0 | 49.0 | 49.0 | ||||||||||||
Northern Alberta | 5.0 | 5.0 | 5.0 | 5.0 | ||||||||||||
Pembina | 7.0 | 4.4 | 7.0 | 4.4 | ||||||||||||
SE Saskatchewan & Manitoba (2) | 11.0 | 2.9 | 11.0 | 2.9 | ||||||||||||
Total | 72.0 | 61.4 | 72.0 | 61.4 |
By Well Type | Development Wells (1) | Total (1) | ||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Crude Oil | 41.0 | 32.7 | 41.0 | 32.7 | ||||||||||||
Natural Gas | 30.0 | 28.5 | 30.0 | 28.5 | ||||||||||||
Dry | 1.0 | 0.16 | 1.0 | 0.16 | ||||||||||||
Total | 72.0 | 61.4 | 72.0 | 61.4 |
1) | Number of wells based on rig release dates. |
2) | ARC divested its properties in Manitoba in the fourth quarter of 2015. |
TOTAL PROVED | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Light Crude Oil & Medium Crude Oil (bbl/d) | Heavy Crude Oil (bbl/d) | Tight Oil (bbl/d) | Conventional Natural Gas (Mcf/d) | Shale Gas (Mcf/d) | Coal Bed Methane (Mcf/d) | Natural Gas Liquids (bbl/d) | Total (boe/d) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||||||||||||||
Dawson | - | - | - | - | - | - | - | - | 148,899 | 137,003 | - | - | 842 | 704 | 25,659 | 23,537 | ||||||||||||||||||||||||||||||||||||||||||||||||
Other Properties | 18,007 | 16,511 | 402 | 832 | 10,199 | 8,636 | 29,926 | 24,847 | 242,869 | 225,982 | 2,829 | 2,674 | 5,898 | 4,681 | 79,942 | 72,911 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved | 18,007 | 16,511 | 402 | 832 | 10,199 | 8,636 | 29,926 | 24,847 | 391,768 | 362,985 | 2,829 | 2,674 | 6,740 | 5,385 | 105,601 | 96,448 |
TOTAL PROBABLE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Light Crude Oil & Medium Crude Oil (bbl/d) | Heavy Crude Oil (bbl/d) | Tight Oil (bbl/d) | Conventional Natural Gas (Mcf/d) | Shale Gas (Mcf/d) | Coal Bed Methane (Mcf/d) | Natural Gas Liquids (bbl/d) | Total (boe/d) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||||||||||||||
Dawson | - | - | - | - | - | - | - | - | 16,542 | 15,635 | - | - | 94 | 83 | 2,851 | 2,689 | ||||||||||||||||||||||||||||||||||||||||||||||||
Other Properties | 1,099 | 990 | 6 | 23 | 2,821 | 2,288 | 1,046 | 951 | 50,472 | 47,435 | 33 | 32 | 1,856 | 1,620 | 14,374 | 12,990 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Probable | 1,099 | 990 | 6 | 23 | 2,821 | 2,288 | 1,046 | 951 | 67,014 | 63,070 | 33 | 32 | 1,949 | 1,703 | 17,224 | 15,679 |
2015 Annual Information Form – ARC Resources Ltd. | Page 27 |
TOTAL PROVED PLUS PROBABLE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Light Crude Oil & Medium Crude Oil (bbl/d) | Heavy Crude Oil (bbl/d) | Tight Oil (bbl/d) | Conventional Natural Gas (Mcf/d) | Shale Gas (Mcf/d) | Coal Bed Methane (Mcf/d) | Natural Gas Liquids (bbl/d) | Total (boe/d) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||||||||||||||
Dawson | - | - | - | - | - | - | - | - | 165,441 | 152,638 | - | - | 28,509 | 26,226 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Other Properties | 19,106 | 17,501 | 408 | 854 | 13,021 | 10,925 | 27,972 | 25,798 | 293,342 | 273,417 | 2,861 | 2,706 | 7,753 | 6,301 | 94,316 | 85,901 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved + Probable | 19,106 | 17,501 | 408 | 854 | 13,021 | 10,925 | 27,972 | 25,798 | 458,783 | 426,055 | 2,861 | 2,706 | 8,689 | 7,088 | 122,825 | 112,127 |
Production History | Quarter Ended 2015 | Year Ended | ||||||||||||||||||
Mar 31 | June 30 | Sept 30 | Dec 31 | 2015 | ||||||||||||||||
Average Daily Production (1) | ||||||||||||||||||||
Light and Medium Crude Oil (bbl/d) (2) | 34,740 | 30,979 | 28,516 | 33,124 | 31,827 | |||||||||||||||
Heavy Oil (bbl/d) | 1,111 | 979 | 881 | 775 | 935 | |||||||||||||||
Gas (MMcf/d) (3) | 459.6 | 426.0 | 425.1 | 469.1 | 444.9 | |||||||||||||||
Natural Gas Liquids (bbl/d) (4) | 7,905 | 6,934 | 7,014 | 7,154 | 7,249 | |||||||||||||||
Condensate (bbl/d) | 3,591 | 3,139 | 3,361 | 3,631 | 3,430 | |||||||||||||||
NGLs (bbl/d) (5) | 4,314 | 3,795 | 3,653 | 3,523 | 3,819 | |||||||||||||||
Total (boe/d) | 120,354 | 109,900 | 107,261 | 119,243 | 114,167 | |||||||||||||||
Average Net Production Prices Received | ||||||||||||||||||||
Light and Medium Crude Oil ($/bbl) (2) | 49.13 | 64.95 | 52.81 | 49.66 | 53.94 | |||||||||||||||
Heavy Oil ($/bbl) | 36.26 | 50.03 | 40.00 | 31.26 | 39.70 | |||||||||||||||
Gas ($/Mcf) (3) | 3.05 | 2.88 | 3.03 | 2.59 | 2.88 | |||||||||||||||
Natural Gas Liquids ($/bbl) (4) | 31.08 | 34.57 | 28.36 | 30.56 | 31.12 | |||||||||||||||
Condensate ($/bbl) | 49.12 | 64.84 | 53.00 | 49.80 | 53.84 | |||||||||||||||
NGLs ($/bbl) (5) | 16.07 | 9.53 | 5.68 | 10.73 | 10.70 | |||||||||||||||
Total ($/boe) (6) | 28.31 | 32.17 | 28.31 | 26.06 | 28.65 | |||||||||||||||
Royalties Paid | ||||||||||||||||||||
Light and Medium Crude Oil ($/bbl) (2) | 5.80 | 5.40 | 6.08 | 5.65 | 5.72 | |||||||||||||||
Heavy Oil ($/bbl) | 1.29 | 1.24 | (0.19 | ) | 1.03 | 0.87 | ||||||||||||||
Gas ($/Mcf) (3) | 0.20 | 0.16 | 0.16 | 0.04 | 0.14 | |||||||||||||||
Natural Gas Liquids ($/bbl) (4) | 5.37 | 5.82 | 5.42 | 4.97 | 5.39 | |||||||||||||||
Condensate ($/bbl) | 8.86 | 10.68 | 8.87 | 7.95 | 9.03 | |||||||||||||||
NGLs ($/bbl) 5) | 2.47 | 1.80 | 2.24 | 1.91 | 2.12 | |||||||||||||||
Total ($/boe) | 2.80 | 2.50 | 2.59 | 2.03 | 2.48 | |||||||||||||||
Operating Expenses (7)(8) | ||||||||||||||||||||
Light and Medium Crude Oil ($/bbl) (2) | 11.74 | 14.26 | 13.68 | 11.45 | 12.78 | |||||||||||||||
Heavy Oil ($/bbl) | 14.69 | 8.83 | 6.41 | 13.03 | 10.38 | |||||||||||||||
Gas ($/Mcf) (3) | 0.88 | 0.91 | 0.79 | 0.66 | 0.80 | |||||||||||||||
Natural Gas Liquids ($/bbl) (4) | 5.13 | 6.48 | 5.71 | 5.66 | 5.92 | |||||||||||||||
Condensate ($/bbl) | 4.82 | 5.97 | 5.09 | 5.19 | 5.78 | |||||||||||||||
NGLs ($/bbl) (5) | 5.46 | 6.94 | 6.30 | 6.15 | 6.05 | |||||||||||||||
Total ($/boe) | 7.24 | 8.05 | 7.18 | 6.21 | 7.15 | |||||||||||||||
Transportation Paid | ||||||||||||||||||||
Light and Medium Crude Oil ($/bbl) (2) | 2.92 | 2.47 | 2.30 | 2.54 | 2.57 | |||||||||||||||
Heavy Oil ($/bbl) | 0.61 | 0.42 | 0.58 | 0.48 | 0.52 | |||||||||||||||
Gas ($/Mcf) (3) | 0.30 | 0.33 | 0.37 | 0.30 | 0.32 | |||||||||||||||
Natural Gas Liquids ($/bbl) (4) | 5.80 | 5.29 | 5.75 | 5.26 | 5.53 | |||||||||||||||
Condensate ($/bbl) | 2.96 | 2.56 | 3.32 | 3.10 | 3.00 | |||||||||||||||
NGLs ($/bbl) (5) | 8.15 | 7.55 | 7.99 | 7.49 | 7.81 | |||||||||||||||
Total ($/boe) | 2.36 | 2.33 | 2.44 | 2.19 | 2.33 |
2015 Annual Information Form – ARC Resources Ltd. | Page 28 |
Production History | Quarter Ended 2015 | Year Ended | ||||||||||||||||||
Mar 31 | June 30 | Sept 30 | Dec 31 | 2015 | ||||||||||||||||
(Loss)/Gain on Commodity Contracts | ||||||||||||||||||||
Light and Medium Crude Oil ($/bbl) (2) | 5.25 | 6.43 | 2.67 | 3.89 | 4.59 | |||||||||||||||
Heavy Oil ($/bbl) | - | - | - | - | - | |||||||||||||||
Gas ($/Mcf) (3) | 0.68 | 0.84 | 0.81 | 0.93 | 0.82 | |||||||||||||||
Natural Gas Liquids ($/bbl) (4) | - | - | - | - | - | |||||||||||||||
Condensate ($/bbl) | - | - | - | - | - | |||||||||||||||
NGLs ($/bbl) (5) | - | - | - | - | - | |||||||||||||||
Total ($/boe) | 4.12 | 5.08 | 3.93 | 4.73 | 4.46 | |||||||||||||||
Netback Received (9) | ||||||||||||||||||||
Light and Medium Crude Oil ($/bbl) (2) | 33.92 | 49.25 | 33.42 | 33.91 | 37.46 | |||||||||||||||
Heavy Oil ($/bbl) | 19.67 | 39.54 | 33.20 | 16.72 | 27.93 | |||||||||||||||
Gas ($/Mcf) (3) | 2.35 | 2.32 | 2.52 | 2.52 | 2.44 | |||||||||||||||
Natural Gas Liquids ($/bbl) (4) | 14.78 | 16.97 | 11.48 | 14.66 | 14.27 | |||||||||||||||
Condensate ($/bbl) | 31.84 | 45.63 | 35.72 | 33.56 | 36.03 | |||||||||||||||
NGLs ($/bbl) (5) | 0.63 | (6.76 | ) | (10.85 | ) | (4.82 | ) | (5.28 | ) | |||||||||||
Total ($/boe) | 20.03 | 24.37 | 20.03 | 20.36 | 21.15 |
1) | Before deduction of royalties and including royalty interests. |
2) | Light and Medium Crude Oil as defined by ARC in external reporting includes light crude oil, medium crude oil and tight oil. |
3) | Gas as defined by ARC in external reporting includes conventional natural gas, shale gas and coal bed methane. |
4) | Natural Gas Liquids as defined by GLJ which includes condensate, butane, ethane and propane. |
5) | NGLs or natural gas liquids as defined by ARC in external reporting includes butane, ethane and propane but excludes condensate. |
6) | Total average price received includes other income from standard business activities including interest earned on ARC’s reclamation fund. |
7) | Operating expenses are composed of direct costs incurred to operate both oil and gas wells. A number of assumptions have been made in allocating these costs between oil, natural gas, condensate and natural gas liquids production. |
8) | Operating recoveries associated with operated properties were excluded from operating costs and accounted for as a reduction to general and administrative costs. |
9) | Netbacks are calculated by subtracting royalties, operating expenses, transportation costs, and realized (losses)/gains on commodity contracts from revenues. Netbacks before hedging can be found in Table 16 and 16a “Netbacks prior to hedging” under the section Operating Netbacks of our Management’s Discussion and Analysis for the year ended December 31, 2015 which has been filed on our SEDAR profile at www.sedar.com. |
2015 Annual Information Form – ARC Resources Ltd. | Page 29 |
2015 Annual Information Form – ARC Resources Ltd. | Page 30 |
2015 Annual Information Form – ARC Resources Ltd. | Page 31 |
— | Long-term debt and letters of credit not to exceed 3.25 trailing 12 month net income before non-cash items, income tax and interest expense; |
— | Long-term debt, letters of credit and subordinated debt not to exceed four times trailing 12 month net income before non-cash items, income tax and interest expense; and |
— | Long-term debt and letters of credit not to exceed 50 per cent of Shareholders' equity and long-term debt, letters of credit and subordinated debt. |
2015 Annual Information Form – ARC Resources Ltd. | Page 32 |
2015 Annual Information Form – ARC Resources Ltd. | Page 33 |
Directors (1) | ||
Name and Municipality of Residence | Office Held and Time as Director (2) | Principal Occupation |
Mac H. Van Wielingen (3) Calgary, Alberta, Canada | Chairman of the Board and Director since May 3, 1996 | Independent Businessman |
John P. Dielwart Calgary, Alberta, Canada | Director since May 3, 1996 | Vice-Chairman of ARC Financial Corp. |
Fred J. Dyment Calgary, Alberta, Canada | Director since April 17, 2003 | Independent Businessman |
Timothy J. Hearn Calgary, Alberta, Canada | Director since June 22, 2011 | Independent Businessman |
James C. Houck Calgary, Alberta, Canada | Director since February 14, 2008 | Independent Businessman |
Harold N. Kvisle (3) Calgary, Alberta Canada | Director since May 20, 2009 | Independent Businessman |
Kathleen M. O'Neill Toronto, Ontario, Canada | Director since June 1, 2009 | Independent Businesswoman |
Herbert C. Pinder, Jr. Saskatoon, Saskatchewan, Canada | Director since January 1, 2006 | Independent Businessman |
William G. Sembo Calgary, Alberta, Canada | Director since November 6, 2013 | Independent Businessman |
Myron M. Stadnyk Calgary, Alberta, Canada | Director since January 1, 2013 | President and Chief Executive Officer of ARC Resources |
1) | Subsequent to 2015 year-end, Nancy L. Smith was appointed to the Board of Directors on February 10, 2016. |
2) | The term of each director is until the next annual meeting of ARC Resources, which is scheduled to be held on April 29, 2016. |
3) | Mac H. Van Wielingen stepped down as Chairman of the Board on December 31, 2015 and on January 1, 2016 Harold N. Kvisle was appointed as Chairman of the Board. |
2015 Annual Information Form – ARC Resources Ltd. | Page 34 |
Officers (1)(2) | ||
Name and Municipality of Residence | Office Held | Principal Occupation |
Myron M. Stadnyk Calgary, Alberta, Canada | President and Chief Executive Officer | President and Chief Executive Officer of ARC Resources |
P. Van R. Dafoe Calgary, Alberta, Canada | Senior Vice President and Chief Financial Officer | Senior Vice President and Chief Financial Officer of ARC Resources |
Terry M. Anderson Calgary, Alberta, Canada | Senior Vice President and Chief Operating Officer | Senior Vice President and Chief Operating Officer of ARC Resources |
David P. Carey Calgary, Alberta, Canada | Senior Vice President, Capital Markets | Senior Vice President, Capital Markets of ARC Resources |
Kristen J. Bibby Calgary, Alberta, Canada | Vice President, Finance | Vice President, Finance of ARC Resources |
Jay B. Billesberger (3) Calgary, Alberta, Canada | Vice President, Information Technology | Vice President, Information Technology of ARC Resources |
Sean R. A. Calder Calgary, Alberta, Canada | Vice President, Production | Vice President, Production of ARC Resources |
Larissa M. Conrad Calgary, Alberta, Canada | Vice President, Engineering | Vice President, Engineering of ARC Resources |
Neil A. Groeneveld Calgary, Alberta, Canada | Vice President, Geosciences and Exploration | Vice President, Geosciences and Exploration of ARC Resources |
Wayne D. Lentz Calgary, Alberta, Canada | Vice President, Strategy and Business Development | Vice President, Strategy and Business Development of ARC Resources |
Karen A. Nielsen Calgary, Alberta, Canada | Vice President, Operations | Vice President, Operations of ARC Resources |
Grant A. Zawalsky (4) Calgary, Alberta, Canada | Corporate Secretary | Managing Partner, Burnet, Duckworth & Palmer LLP (Barristers and Solicitors) |
1) | Subsequent to 2015 year-end, Lisa A. Olsen was promoted to the position of Vice President, Human Resources effective January 1, 2016. |
2) | Subsequent to 2015 year-end, Bevin Wirzba joined ARC on January 1, 2016 as Senior Vice President, Business Development. |
3) | Subsequent to 2015 year-end, Jay B. Billesberger ceased to be an employee of ARC as of January 5, 2016. |
4) | Mr. Zawalsky is not considered to be an "executive officer" of ARC as defined by NI 51-102 as he does not perform a policy-making function in respect of the Corporation. |
Name of Director | Audit | Reserves | Risk | Human Resources & Compensation | Policy & Board Governance | Health, Safety & Environment |
Non-Independent Directors | ||||||
John P. Dielwart | √ | Chair | ||||
Independent Directors | ||||||
Mac H. Van Wielingen | √ | √ | √ | |||
Fred J. Dyment | √ | Chair | √ | |||
Timothy J. Hearn | Chair | √ | √ | |||
James C. Houck | √ | Chair | √ | |||
Harold N. Kvisle | √ | √ | ||||
Kathleen M. O'Neill | Chair | √ | √ | |||
Herbert C. Pinder, Jr. | √ | √ | Chair | |||
William G. Sembo | √ | √ |
2015 Annual Information Form – ARC Resources Ltd. | Page 35 |
— | Prior to May 2015, Harold N. Kvisle was President and Chief Executive Officer of Talisman Energy, and prior to September 2012 was an independent businessman. |
— | Prior to August 2014, Kristen J. Bibby was VP Finance and Chief Financial Officer at Verano Energy Limited, and prior to January 2011 was VP Finance and Chief Financial Officer of Petrolifera Petroleum Limited. |
— | Prior to February 2014, P. Van R. Dafoe was Senior Vice President, Finance at ARC Resources. |
— | Prior to February 2014, Larissa M. Conrad was Manager, Engineering South at ARC Resources, and prior to August 2011 was Team Lead, Government & Regulatory Relations at EnCana Corporation. |
— | Prior to January 2014, Terry M. Anderson was Senior Vice President, Engineering at ARC Resources. |
— | Prior to September 23, Sean R. A. Calder was Manager, Technical Operations North at ARC Resources. |
— | Prior to August 2013, Karen A. Nielsen was Vice President, Engineering of Birchcliff Energy Ltd. |
— | Prior to January 2013, Myron Stadnyk was President and Chief Operating Officer of ARC Resources. |
— | Prior to January 2013, John P. Dielwart was Chief Executive Officer of ARC Resources. |
— | Prior to August 2012, James C. Houck was President and Chief Executive Officer of The Churchill Corporation. |
— | Prior to July 2011, Wayne D. Lentz was Manager, Strategic Planning at ARC Resources. |
2015 Annual Information Form – ARC Resources Ltd. | Page 36 |
2015 Annual Information Form – ARC Resources Ltd. | Page 37 |
2015 Annual Information Form – ARC Resources Ltd. | Page 38 |
2015 Annual Information Form – ARC Resources Ltd. | Page 39 |
Summary of External Audit and Non-Audit Service Fees | 2015 | 2014 | ||||||
Audit Fees | $ | 872,585 | $ | 903,578 | ||||
Audit Related Fees (1) | $ | 70,727 | $ | 70,727 | ||||
All Other Fees (2) | $ | 18,781 | $ | 112,703 |
1) | The aggregate fees billed by our external auditor for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements but which are not included in audit services fees. |
2) | The assessment fee billed by The Canadian Public Accountability Board per the National Instrument 52-108 Auditor Oversight mandate for reporting issuers to have an audit completed by a CPAB participant firm, as well as fees paid in 2014 for a security and vulnerability assessment of the Company’s information technology environment. |
2015 Annual Information Form – ARC Resources Ltd. | Page 41 |
Dividends | 2015 | 2014 | 2013 | |||||||||
January | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
February | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
March | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
April | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
May | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
June | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
July | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
August | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
September | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
October | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
November | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
December | $ | 0.10 | $ | 0.10 | $ | 0.10 | ||||||
Total | $ | 1.20 | $ | 1.20 | $ | 1.20 |
2015 Annual Information Form – ARC Resources Ltd. | Page 42 |
Toronto Stock Exchange 2015 Period | High $ | Low $ | Volume | |||||||||
January | 25.75 | 20.96 | 47,450,000 | |||||||||
February | 25.06 | 23.33 | 33,450,000 | |||||||||
March | 24.51 | 21.36 | 39,660,000 | |||||||||
April | 25.23 | 22.03 | 31,750,000 | |||||||||
May | 24.97 | 22.47 | 26,000,000 | |||||||||
June | 22.80 | 21.18 | 31,940,000 | |||||||||
July | 21.80 | 18.69 | 35,010,000 | |||||||||
August | 20.32 | 16.23 | 36,700,000 | |||||||||
September | 19.01 | 17.06 | 37,660,000 | |||||||||
October | 22.27 | 17.56 | 48,960,000 | |||||||||
November | 20.55 | 17.46 | 41,770,000 | |||||||||
December | 18.60 | 15.95 | 49,400,000 |
2015 Annual Information Form – ARC Resources Ltd. | Page 43 |
2015 Annual Information Form – ARC Resources Ltd. | Page 44 |
On January 29, 2016, the Government of Alberta released and accepted the Royalty Review Advisory Panel's recommendations, which outlined the implementation of a "Modernized Royalty Framework" for Alberta (the "MRF"). The MRF will take effect on January 1, 2017. Wells drilled prior to January 1, 2017 will continue to be governed by the current "Alberta Royalty Framework" for a period of 10 years, until January 1, 2027. The MRF is structured in three phases: (i) Pre-Payout, (ii) Mid-Life, and (iii) Mature. During the Pre-Payout phase, a fixed five per cent royalty will apply until the well reaches payout. Well payout occurs when the cumulative revenue from a well is equal to the Drilling and Completion Cost Allowance (determined by a formula that approximates drilling and completion costs for wells based on depth, length and historical costs). The new royalty rate will be payable on gross revenue generated from all production streams (oil, gas, and natural gas liquids), eliminating the need to label a well as "oil" or "gas". Post-payout, the Mid-Life phase will apply a higher royalty rate than the Pre-Payout phase. While the metrics for calculating the Mid-Life phase royalty have yet to be released, the rate will be determined based on commodity prices
2015 Annual Information Form – ARC Resources Ltd. | Page 45 |
— | Horizontal oil wells will receive a maximum royalty rate of five per cent with volume and production month limits set according to the depth of the well (including the horizontal distance), retroactive to wells that commenced drilling on or after May 1, 2010; and |
— | Horizontal gas wells will receive a maximum royalty rate of five per cent for 18 producing months on up to 500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010. |
The royalty payable in respect of natural gas produced on Crown lands is determined by a sliding scale formula based on a reference price, which is the greater of the average net price obtained by the producer and a prescribed minimum price. For non-conservation gas (not produced in association with oil), the royalty rate depends on the date of acquisition of the oil and natural gas tenure rights and the spud date of the well and may also be impacted by the select price, a parameter used in the royalty rate formula to account for inflation. Royalties on natural gas liquids are levied at a flat rate of 20 per cent of the sales volume.
2015 Annual Information Form – ARC Resources Ltd. | Page 46 |
— | Deep Well Royalty Credit Program, which provides a royalty credit for natural gas wells defined in terms of a dollar amount applied against royalties, is well specific and applies to drilling and completion costs for vertical wells with a true vertical depth greater than 2,500 metres and horizontal wells with a true vertical depth greater than 1,900 metres (or 2,300 metres if spud before September 1, 2009) and if certain other criteria are met and is intended to reflect the higher drilling and completion costs. Effective April 1, 2014, the Deep Well Royalty Credit Program was extended to include a second tier which applies to horizontal wells with a true vertical depth of less than 1,900 meters if spud after March 31, 2014. |
— | Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002 provides reduced Crown royalty and freehold tax rates on incentive volumes of 6,000 m3 for non-deep horizontal oil wells and 16,000 m3 for deep horizontal oil wells (more than 1,700 metres total vertical depth or within certain formations) and after the incentive volume is produced, the oil produced will be subject to the "fourth tier" royalty tax rate; |
— | Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects Implemented on or after October 1, 2002 whereby incremental production from approved waterflood projects is treated as fourth tier oil for the purposes of Crown royalty and freehold tax calculations; |
— | Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing prior to April 1, 2005 provides lower Crown royalty and freehold tax determinations based in part on the profitability of EOR projects during and subsequent to the payout of the EOR operations; |
2015 Annual Information Form – ARC Resources Ltd. | Page 47 |
— | Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing on or after April 1, 2005 provides a Crown royalty of one per cent of gross revenues on EOR projects pre-payout and 20 per cent of EOR operating income post-payout and a freehold production tax of zero per cent pre-payout and eight per cent post-payout on operating income from EOR projects; and |
— | Royalty/Tax Regime for High Water-Cut Oil Wells designed to extend the product lives and improve the recovery rates of high water-cut oil wells and granting "third tier oil" royalty/tax rates to incremental high water-cut oil production resulting from qualifying investments made to rejuvenate eligible oil wells and/or associated facilities. |
— | Horizontal Well Incentive provides an a holiday oil volume (“HOV”) of 8,000 m3 for any horizontal well drilled after December 31, 2014 and prior to January 1, 2019 achieving an angle of at least 80 degrees for a minimum distance of 100 meters; and |
— | Pressure Maintenance Project Incentive provides a one-year exemption from the payment of Crown royalties or freehold production taxes for a unit tract in which an injection well is drilled or a well is converted to water injection. For a well that is converted to injection after December 31, 2014 and before January 21, 2019 and that has a remaining HOV, the exemption will be extended to 18 months. |
The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western provinces, with the exception of Manitoba where private ownership accounts for approximately 80 per cent of the crude oil and natural gas rights in the southwestern portion of the province. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.
2015 Annual Information Form – ARC Resources Ltd. | Page 48 |
The Government of Alberta relies on regional planning to accomplish its responsible resource development goals. The following frameworks, plans and policies form the basis of Alberta's Integrated Resource Management System ("IRMS"). The IRMS method to natural resource management sets out to engage and consult with stakeholders and the public. While the AER is the primary regulator for energy development, several governmental departments and agencies may be involved in land use issues, including Alberta Environment and Parks, Alberta Energy, the AER, the Alberta Environmental Monitoring, Evaluation and Reporting Agency, the Policy Management Office, the Aboriginal Consultation Office, and the Land Use Secretariat.
2015 Annual Information Form – ARC Resources Ltd. | Page 49 |
In May 2011, the Government of Saskatchewan passed changes to The Oil and Gas Conservation Act ("SKOGCA"), the act governing the regulation of resource development operations in the province. Although the associated Bill received Royal Assent on May 18, 2011, it was not proclaimed into force until April 1, 2012, in conjunction with the release of The Oil and Gas Conservation Regulations, 2012 ("OGCR") and The Petroleum Registry and Electronic Documents Regulations ("Registry Regulations"). The aim of the amendments to the SKOGCA, and the associated regulations, is to provide resource companies investing in Saskatchewan's energy and resource industries with the best support services and business and regulatory systems available. With the enactment of the Registry Regulations and the OGCR, the Government of Saskatchewan has implemented a number of operational aspects, including the increased demand for record-keeping, increased testing requirements for injection wells and increased investigation
2015 Annual Information Form – ARC Resources Ltd. | Page 50 |
In British Columbia, the Commission implements the Liability Management Rating ("LMR") Program, designed to manage public liability exposure related to oil and gas activities by ensuring that permit holders carry the financial risks and regulatory responsibility of their operations through to regulatory closure. Under the LMR Program, the Commission determines the required security deposits for permit holders under the OGAA. The LMR is the ratio of a permit holder's deemed assets to deemed liabilities. Permit holders whose deemed liabilities exceed deemed assets will be considered high risk and reviewed for a security deposit. Permit holders who fail to submit the required security deposit within the allotted timeframe may be in non-compliance with the OGAA.
2015 Annual Information Form – ARC Resources Ltd. | Page 51 |
On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action Plan outlines emissions intensity-based targets, for application to regulated sectors on a facility-specific basis, sector-wide basis or company-by-company basis. Although the intention was for draft regulations aimed at implementing the Updated Action Plan to become binding on January 1, 2010, the only regulations being implemented are in the transportation and electricity sectors. The federal government indicates that it is taking a sector-by-sector regulatory approach to reducing GHG emissions and is working on regulations for other sectors. Representatives of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation. In June 2012, the second US-Canada Clean Energy Dialogue Action Plan was released. The plan renewed efforts to enhance bilateral collaboration on the development of clean energy technologies to reduce GHG emissions.
2015 Annual Information Form – ARC Resources Ltd. | Page 52 |
In February 2008, the Government of British Columbia announced a revenue-neutral carbon tax that took effect July 1, 2008. The tax is consumption-based and applied at the time of retail sale or consumption of virtually all fossil fuels purchased or used in British Columbia. The current tax level is $30 per tonne of GHG emissions. The final scheduled increase took effect on July 1, 2012. There is no plan for further rate increases or expansions at this time. In order to make the tax revenue-neutral, the Government of British Columbia has implemented tax credits and reductions in order to offset the tax revenues that the Government of British Columbia would otherwise receive from the tax.
2015 Annual Information Form – ARC Resources Ltd. | Page 53 |
ARC divested its Manitoba assets in the fourth quarter of 2015 and no longer holds any Manitoba producing assets as of December 31, 2015.
2015 Annual Information Form – ARC Resources Ltd. | Page 54 |
Primarily due to aging infrastructure, certain pipeline leaks have gained media, environmental and other stakeholder attention. Such incidents may result in additional regulation or changes in law which could impede the conduct of our business or make our operations more expensive.
2015 Annual Information Form – ARC Resources Ltd. | Page 55 |
We actively manage the risk associated with changes in commodity prices by entering into oil and natural gas price hedges. If we hedge our commodity price exposure, we will forego some of the benefits we would otherwise experience if commodity prices were to increase, and some of these foregone benefits may be material relative to funds from operations. For more information in relation to our commodity hedging program, see "Statement of Reserve Data and Other Oil and Gas Information – Forward Contracts". We also may initiate certain hedges to attempt to mitigate the risk of the Canadian dollar fluctuating in relation to the U.S. dollar. These hedging activities
2015 Annual Information Form – ARC Resources Ltd. | Page 56 |
Provincial regulation requires the reclamation and abandonment of wells at the end of their production life. We have established a reclamation fund for the purpose of funding our currently estimated future environmental and reclamation obligations for our assets at Redwater. We have not established a reclamation fund for any of our other assets. There can be no assurance that we will be able to satisfy our actual future environmental and reclamation obligations for our assets at Redwater or elsewhere.
2015 Annual Information Form – ARC Resources Ltd. | Page 57 |
From time-to-time we may enter into transactions to acquire assets or shares of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry
2015 Annual Information Form – ARC Resources Ltd. | Page 58 |
Estimates of proved undeveloped reserves are sometimes based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.
2015 Annual Information Form – ARC Resources Ltd. | Page 59 |
We manage a variety of small and large projects in the conduct of our business. We have undertaken large development projects, including the construction of gas processing plants, in northeastern British Columbia for the development of our natural gas reserves. Project delays may impact expected revenues from operations. Significant
2015 Annual Information Form – ARC Resources Ltd. | Page 60 |
— | 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, or our ability to dispose of water used or removed from strata at a reasonable cost and within applicable environmental regulations; |
— | the supply of and demand for oil and natural gas; |
— | the availability of alternative fuel sources; |
— | the effects of inclement weather; |
— | the availability of drilling and related equipment; |
— | unexpected cost increases; |
— | accidental events; |
— | 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. |
Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities.
2015 Annual Information Form – ARC Resources Ltd. | Page 61 |
2015 Annual Information Form – ARC Resources Ltd. | Page 62 |
2015 Annual Information Form – ARC Resources Ltd. | Page 63 |
2015 Annual Information Form – ARC Resources Ltd. | Page 64 |
1. | Amended and Restated Credit Agreement dated as of November 6, 2014 between ARC Resources and a syndicate of lenders, and an administrative agent, providing for an extendible revolving credit facility up to Cdn$1 billion. The maturity date of the facility was extended to November 6, 2019 under the existing terms on October 26, 2015. |
2. | Uncommitted Master Shelf Agreement dated as of November 16, 2000 between ARC Resources and various purchasers, as amended and restated on December 15, 2005 and as amended and restated on September 25, 2014 providing for the issuance and sale of up to an aggregate principal amount of US$350 million in notes of which US$18.8 million 5.42% Series C Notes due December 15, 2017, US$40 million 4.98% Series D Notes due March 5, 2019 and US$150 million 3.72% Series E Notes due September 25, 2026 are currently outstanding. |
3. | Note Purchase Agreement dated as of April 27, 2004 between ARC Resources and various purchasers, as amended on April 14, 2009, March 31, 2010 and January 1, 2011, with respect to US$62.5 million 4.62% Series A Notes due April 27, 2014 and US$62.5 million 5.10% Series B Notes due April 27, 2016 of which US$0 and US$4.8 million, respectively, are currently outstanding. |
4. | Note Purchase Agreement dated as of April 14, 2009 between ARC Resources and various purchasers, as amended January 1, 2011 with respect to US$67.5 million 7.19% Series C Notes due April 14, 2016, US$35 million 8.21% Series D Notes due April 14, 2021 and Cdn$29 million 6.50% Series E Notes due April 14, 2016 of which US$13.5 million, US$35 million and Cdn$5.8 million, respectively, are currently outstanding. |
5. | Note Purchase Agreement dated as of May 27, 2010 between ARC Resources and various purchasers, as amended January 1, 2011 with respect to US$150 million 5.36% Series F Notes due May 27, 2022, of which US$150 million is currently outstanding. |
6. | Note Purchase Agreement dated as of August 23, 2012 between ARC Resources and various purchasers with respect to US$60 million 3.31% Series G Notes due August 23, 2021, US$300 million 3.81% Series H Notes due August 23, 2024 and Cdn$40 million 4.49% Series I Notes due August 23, 2024, of which US$60 million, US$300 million and Cdn$40 million, respectively, is currently outstanding. |
2015 Annual Information Form – ARC Resources Ltd. | Page 65 |
2015 Annual Information Form – ARC Resources Ltd. | Page 66 |
FORM 51-101F2
1. | We have evaluated the Company's reserves data and contingent resources data and as at December 31, 2015. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2015, estimated using forecast prices and costs. The contingent resources data are risked estimates of volume of contingent resources and related risked net present value of future net revenue as at December 31, 2015, estimated using forecast prices and costs. |
2. | The reserves data and contingent resources data are the responsibility of the Company'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 Company evaluated for the year ended December 31, 2015, and identifies the respective portions thereof that we have evaluated and reported on to the Company's board of directors: |
Independent Qualified Reserves Evaluator or Auditor | Effective Date of Evaluation Report (Mo/Dy/Yr) | 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 | 12/31/15 | Canada | - | 5,138,885 | - | 5,138,885 |
6. | The following tables set forth the risked volume and risked net present value of future net revenue of contingent resources (before deduction of income taxes) attributed to contingent resources, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the Company'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 Company's board of directors: |
2015 Annual Information Form – ARC Resources Ltd. | Page A-1 |
Classification | Independent Qualified Reserves Evaluator or Auditor | Effective Date of Evaluation Report (Mo/Dy/Yr) | 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 | 12/31/15 | Canada | 470.7 | - | 1,153,921 | 1,153,921 |
Classification | Independent Qualified Reserves Evaluator or Auditor | Effective Date of Evaluation Report (Mo/Dy/Yr) | Location of Resources Other than Reserves (Country or Foreign Geographic Area) | Risked Volume (MMboe) | ||||||
Contingent Resources Development Unclarified | GLJ Petroleum Consultants | 12/31/15 | Canada | 879.0 | ||||||
Contingent Resources Development Not Viable | GLJ Petroleum Consultants | 12/31/15 | Canada | 142.2 |
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. |
“Originally Signed by” |
Bryan M. Joa, P. Eng. |
Vice President |
2015 Annual Information Form – ARC Resources Ltd. | Page A-2 |
FORM 51-101F3
a) | reviewed the Company's procedures for providing information to the independent qualified reserves evaluator; |
b) | met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and |
c) | reviewed the reserves data and 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; and |
c) | the content and filing of this report. |
(signed) "Myron Stadnyk" | (signed) "Terry Anderson" |
Myron Stadnyk | Terry Anderson |
President and Chief Executive Officer | Senior Vice President and Chief Operating Officer |
(signed) "James Houck" | (signed) "Fred J. Dyment" |
James Houck | Fred J. Dyment |
Director and Chair of the Reserves Committee | Director and Member of the Reserves Committee |
March 9, 2016 |
2015 Annual Information Form – ARC Resources Ltd. | Page B-1 |
Contingent Resources (1)(2) | ||||||||||||||||||||||||||||||||
Resources Project Maturity Sub-Class | Tight Oil | Shale Gas | Natural Gas Liquids | Oil Equivalent | ||||||||||||||||||||||||||||
Gross (Mbbl) | Net (Mbbl) | Gross (Bcf) | Net (Bcf) | Gross (Mbbl) | Net (Mbbl) | Gross (Mboe) | Net (Mboe) | |||||||||||||||||||||||||
Contingent (2C) | ||||||||||||||||||||||||||||||||
Development Pending | 33,079 | 28,737 | 2,404.3 | 1,934.0 | 36,898 | 30,438 | 470,690 | 381,502 | ||||||||||||||||||||||||
Development Unclarified | 129,032 | 101,787 | 3,294.8 | 2,496.6 | 200,861 | 133,235 | 879,026 | 651,127 | ||||||||||||||||||||||||
Development Not Viable | - | - | 537.3 | 403.5 | 52,651 | 32,945 | 142,203 | 100,192 |
1) | All volumes listed in the table are risked, company gross and sales volumes. |
2) | Refer to “Resource Definitions” in this Appendix C for detailed definitions of Contingent Resources, Development Pending, Development Unclarified and Development Not Viable. |
2015 Annual Information Form – ARC Resources Ltd. | Page C-1 |
Risked Net Present Value of Future Net Revenue (1) | ||||||||||||||||||||||||||||||||||||||||
Resources Project Maturity Sub-Class ($ millions) | Before Income Taxes Discounted at % per Year | After Income Taxes Discounted at % per Year | ||||||||||||||||||||||||||||||||||||||
0 | 5 | 10 | 15 | 20 | 0 | 5 | 10 | 15 | 20 | |||||||||||||||||||||||||||||||
Contingent (2C) | ||||||||||||||||||||||||||||||||||||||||
Development Pending | 9,890 | 3,203 | 1,154 | 406 | 100 | 7,194 | 2,258 | 750 | 208 | (8 | ) |
1) | NPV as per GLJ Independent Resources Evaluation as of December 31, 2015 and based on GLJ forecast pricing at January 1, 2016. |
- | Economic Factor: for Development Pending associated development projects had robust economics (i.e. strong rate of returns), and as such assigned a factor of one. The remaining sub-classes have factors ranging from 0.80 to 0.95. |
2015 Annual Information Form – ARC Resources Ltd. | Page C-2 |
- | Technology Factor: ARC’s NEBC Montney will be developed utilizing established technology, therefore, a technology factor of one is utilized for all resource sub-classes. |
- | Development Plan Factor: detailed development plans and costs were prepared and are in place. This factor ranges from 0.90 to 1.0 for Development Pending CR. Factors less than one account for projects where final pad placement and well locations are less certain. For the remaining sub-classes, the Development Plan Factors range from 0.70 to 0.90 based on the level of details provided. |
- | Development Timeframe Factor: several core areas within the Evaluated Areas have portions of the PIIP volume developed and producing, with proved and probable reserves assigned. Timing for the CR portions of these projects will depend on the pace of continued development (including allocation of funds), available throughput capacity in existing facilities, or construction of additional facilities. Development Pending projects have been assigned Development Timeframe Factors ranging from 0.90 to 0.95 reflecting the apparent certainty in timing estimates. For the remaining sub-classes, the Timeframe Factors assigned range from 0.70 to 0.90. |
- | Other Contingency Factor: for reserves to be assessed, all contingencies must be eliminated. With respect to contingent resources, this factor captures major contingencies, usually beyond the control of ARC, other than those captured by economic status, technology status, project evaluation scenario status and the development timeframe. The Other Contingency Factor has been assessed as one for all CR sub-classes. |
Chance of | Best Estimate | Best Estimate | ||||||||||
2015 Risked CR, Unrisked CR and Chance of Development (1)(2) | Development | Unrisked | Risked | |||||||||
Shale Gas (Tcf) | ||||||||||||
Development Pending CR | 92 | % | 2.6 | 2.4 | ||||||||
Development Unclarified CR | 76 | % | 4.4 | 3.3 | ||||||||
Development Not Viable CR | 44 | % | 1.2 | 0.5 | ||||||||
NGLs (MMbbl) | ||||||||||||
Development Pending CR | 94 | % | 39.1 | 36.9 | ||||||||
Development Unclarified CR | 76 | % | 265.1 | 200.9 | ||||||||
Development Not Viable CR | 45 | % | 117.1 | 52.7 | ||||||||
Tight Oil (MMbbl) | ||||||||||||
Development Pending CR | 95 | % | 34.8 | 33.1 | ||||||||
Development Unclarified CR | 79 | % | 163.2 | 129.0 | ||||||||
Development Not Viable CR | - | - | - | |||||||||
Total (MMboe) | ||||||||||||
Development Pending CR | 92 | % | 509.4 | 470.7 | ||||||||
Development Unclarified CR | 76 | % | 1,154.9 | 879.0 | ||||||||
Development Not Viable CR | 45 | % | 318.7 | 142.2 |
1) | All volumes listed in the table are company gross and sales volumes. |
2) | Refer to “Resource Definitions” in this Appendix C for detailed definitions of Contingent Resources, Development Pending, Development Unclarified and Development Not Viable. |
2015 Annual Information Form – ARC Resources Ltd. | Page C-3 |
a) | Fundamental Resource Definitions |
b) | Uncertainty Categories for Resource Estimates |
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c) | Discovered and Commercial Status and Risks Associated with Resource Estimates |
· | economic viability of the related development project; |
· | a reasonable expectation that there will be a market for the expected sales quantities of production required to justify development; |
· | evidence that the necessary production and transportation facilities are available or can be made available; |
· | evidence that legal, contractual, environmental, governmental, and other social and economic concerns will allow for the actual implementation of the recovery project being evaluated; |
· | a reasonable expectation that all required internal and external approvals will be forthcoming. Evidence of this may include items such as signed contracts, budget approvals, and approvals for expenditures, etc.; |
· | evidence to support a reasonable timetable for development. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While five years is recommended as a maximum time frame for classification of a project as commercial, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons or to meet contractual or strategic objectives. |
d) | Recovery Technology Status |
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e) | Economic Status of Resource Estimates |
f) | Project Maturity Sub-Classes for Contingent Resources |
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— | To assist Directors to meet their responsibilities in respect of the preparation and disclosure of the financial statements of the Corporation and related matters. |
— | To provide better communication between Directors and external auditors. |
— | To ensure the external auditors' independence. |
— | To review management’s implementation and maintenance of an effective system of internal control over financial reporting and disclosure control over financial reporting. |
— | To increase the credibility and objectivity of financial reports. |
— | To facilitate in-depth discussions between directors on the Committee, management and external auditors. |
1. | It is a primary responsibility of the Committee to review and recommend for approval to the Board of Directors the annual and quarterly financial statements of the Corporation. The Committee is also to review and recommend to the Board of Directors for approval the financial statements and related information included in prospectuses, management discussion and analysis (MD&A), financial press releases, information circular-proxy statements and annual information forms (AIF). The process should include but not be limited to: |
a. | reviewing changes in accounting principles, or in their application, which may have a material impact on the current or future years' financial statements; |
b. | reviewing significant management judgments and estimates that may be material to financial reporting including alternative treatments and their impacts; |
c. | reviewing the presentation and impact of any significant risks and uncertainties that may be material to financial reporting including alternative treatments and their impacts; |
d. | reviewing accounting treatment of significant, unusual or non-recurring transactions; |
e. | reviewing adjustments raised by the external auditors, whether or not included in the financial statements; |
f. | reviewing unresolved differences between management and the external auditors; |
g. | determining through inquiry if there are any related party transactions and ensure the nature and extent of such transactions are properly disclosed; and |
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h. | reviewing all financial reporting relating to risk exposure including the identification, monitoring and mitigation of business risk and its disclosure. |
2. | The Committee shall satisfy itself that adequate procedures are in place for the review of the Corporation's public disclosure of financial information from the Corporation's financial statements and periodically assess the adequacy of those procedures. |
3. | It is the responsibility of the Committee to satisfy itself on behalf of the Board with respect to the Corporation's internal control over financial reporting and information systems. The process should include but not be limited to: |
a. | inquiring as to the adequacy and effectiveness of the Corporation’s system of internal controls over financial reporting and review the evaluation of internal controls over financial reporting by external auditors; |
b. | establishing procedures for the confidential, anonymous submission by employees of the Corporation of concerns relating to accounting, internal control over financial reporting, auditing or Code of Business Conduct and Ethics matters and periodically review a summary of complaints and their related resolution; and |
c. | establishing procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls, or auditing matters. |
4. | It is the responsibility of the Committee to satisfy itself on behalf of the Board to review management’s process for certification under the Extractive Sector Transparency Measures Act (Canada). |
5. | With respect to the appointment of external auditors by the Board, the Committee shall: |
a. | be directly responsible for overseeing the work of the external auditors engaged for the purpose of issuing an auditors' report or performing other audit, review or attest services for the Corporation, including the resolution of disagreements between management and the external auditor regarding financial reporting; |
b. | review the terms of engagement of the external auditors, including the appropriateness and reasonableness of the auditors' fees; |
c. | recommend to the Board appointment of external auditors and the compensation of the external auditors; |
d. | when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change; |
e. | review and approve any non-audit services to be provided by the external auditors' firm and consider the impact on the independence of the auditors; |
f. | inquire as to the independence of the external auditors and obtain, at least annually, a formal written statement delineating all relationships between the external auditors and the Corporation as contemplated by Independence Standards Board No. 1; and |
g. | discuss with the external auditors, without management being present, the quality of the Corporation’s financial and accounting personnel, the completeness and accuracy of the Corporation’s financial statements and elicit comments of senior management regarding the responsiveness of the external auditors to the Corporation’s needs. |
6. | The Committee shall review with the external auditors (and the internal auditor if one is appointed by the Corporation) their assessment of the internal control over financial reporting of the Corporation, their written reports containing recommendations for improvement of internal control over financial reporting and other suggestions as appropriate, and management's response and follow-up to any identified weaknesses. |
7. | The Committee shall also review and approve annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of the Corporation and its subsidiaries. |
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8. | It is the responsibility of the Committee to review management’s process for the certification of annual and interim financial reports in accordance with required securities legislation. |
9. | It is the responsibility of the Committee to ascertain compliance with covenants under loan agreements. |
10. | The Committee shall review the Corporation’s compliance with all legal and regulatory requirements as it pertains to financial reporting, taxation, internal control over financial reporting and any other area the Committee considers to be appropriate relative to its mandate or as may be requested by the Board of Directors. |
11. | It is the responsibility of the Committee to review and approve the Corporation's hiring policies regarding partners, employees and former partners and employees of the present and external auditors of the Corporation. |
12. | The Committee may also review any other matters that the Audit Committee feels are important to its mandate or that the Board chooses to delegate to it. |
13. | The Committee shall undertake annually a review of this mandate and make recommendations to the Policy and Board Governance Committee as to proposed changes. |
14. | This Committee shall be composed of at least three individuals appointed by the Board from amongst its members, all of which members will be independent (within the meaning of Section 1.4 and 1.5 of National Instrument 52-110 Audit Committees) unless the Board determines to rely on an exemption in NI 52-110. "Independent" generally means free from any business or other direct or indirect material relationship with the Corporation that could, in the view of the Board, be reasonably expected to interfere with the exercise of the member's independent judgment. |
15. | The Chair of the Committee is appointed by the Board of Directors. |
16. | A quorum shall be a majority of the members of the Committee. |
17. | All of the members must be financially literate within the meaning of NI 52-110 unless the Board has determined to rely on an exemption in NI 52-110. Being "financially literate" means members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Corporation's financial statements. |
18. | The Committee shall meet at least four times per year and/or as deemed appropriate by the Committee Chair. |
19. | The Committee shall meet not less than quarterly with the auditors, independent of the presence of management. |
20. | Agendas, with input from management, shall be circulated to Committee members and relevant management personnel along with background information on a timely basis prior to the Committee meetings. |
21. | The Chief Executive Officer and the Chief Financial Officer or their designates shall be available to attend at all meetings of the Committee upon the invitation of the Committee. |
22. | The Controller and such other staff as appropriate to provide information to the Committee shall attend meetings upon invitation by the Committee. |
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23. | Following each meeting, in addition to a verbal report, the Committee will report to the Board by way of providing copies of the minutes of such Committee meeting at the next Board meeting after a meeting is held (these may still be in draft form). |
24. | Supporting schedules and information reviewed by the Committee shall be available for examination by any director. |
25. | The Committee shall have the authority to investigate any financial activity of the Corporation and to communicate directly with the internal and external auditors. All employees are to cooperate as requested by the Committee. |
26. | The Committee may retain, and set and pay the compensation for, persons having special expertise and/or obtain independent professional advice to assist in fulfilling its duties and responsibilities at the expense of the Corporation. |
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