Exhibit 99.4
ANNUAL INFORMATION FORM | 
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FOR THE YEAR ENDED DECEMBER 31, 2015 |
FEBRUARY 26, 2016 |
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REPSOL OIL & GAS CANADA INC. |
REPSOL OIL & GAS CANADA INC. ANNUAL INFORMATION FORM 2015
INDEX
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INTRODUCTION | 1 |
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CORPORATE STRUCTURE | 1 |
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GENERAL DEVELOPMENT OF THE BUSINESS | 2 |
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DESCRIPTION OF THE BUSINESS | 3 |
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RESERVES AND OTHER OIL AND GAS INFORMATION | 8 |
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COMPETITIVE CONDITIONS | 8 |
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CORPORATE RESPONSIBILITY AND ENVIRONMENTAL PROTECTION | 8 |
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EMPLOYEES | 9 |
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DESCRIPTION OF CAPITAL STRUCTURE | 9 |
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MARKET FOR THE SECURITIES OF THE COMPANY | 11 |
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DIRECTORS AND OFFICERS | 11 |
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AUDIT COMMITTEE INFORMATION | 15 |
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LEGAL PROCEEDINGS | 15 |
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RISK FACTORS | 16 |
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TRANSFER AGENTS AND REGISTRARS | 25 |
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INTERESTS OF EXPERTS | 25 |
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ADVISORIES | 25 |
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EXCHANGE RATE INFORMATION | 27 |
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ABBREVIATIONS | 28 |
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MATERIAL CONTRACTS | 29 |
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ADDITIONAL INFORMATION | 29 |
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SCHEDULE A — RESERVES DATA AND OTHER OIL AND GAS INFORMATION | 30 |
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SCHEDULE B — AUDIT COMMITTEE INFORMATION | 66 |
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SCHEDULE C — CORPORATE GOVERNANCE | 74 |
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SCHEDULE D — EXECUTIVE COMPENSATION | 84 |
INTRODUCTION
This document is the Annual Information Form of Repsol Oil & Gas Canada Inc. (“ROGCI” or the “Company”), formerly Talisman Energy Inc., for the year ended December 31, 2015. All information in this Annual Information Form relating to assets owned or held by the Company is as of December 31, 2015, unless otherwise indicated.
On May 8, 2015, Repsol S.A. (“Repsol”) indirectly acquired all of the outstanding shares of the Company. The Company continues to be a reporting issuer under applicable Canadian and United States securities laws and thus continues to be subject to the continuous disclosure obligations applicable to reporting issuers. This Annual Information Form is being filed in accordance with those obligations. Since the Company’s shares are no longer publicly held, the Company will not be preparing and filing with the applicable securities regulators the management proxy circular that would be required for an annual meeting of shareholders. This Annual Information Form includes certain information that the Company is required to disclose that would otherwise be disclosed in a management proxy circular.
Unless the context indicates otherwise, references in this Annual Information Form to “ROGCI” or the “Company” include, for reporting purposes only, the direct or indirect subsidiaries of the Company, partnership interests held by the Company and its subsidiaries, and the Company’s equity interests in Equion Energía Limited (“Equion”) and Talisman Sinopec Energy UK Limited (“TSEUK”) as noted below. Use of “ROGCI” or the “Company” to refer to these subsidiaries, partnership interests and equity interests does not constitute a waiver by the Company or such entities or partnerships of their separate legal status, for any purpose.
The Company has a 49% equity interest in Equion and a 51% equity interest in TSEUK. The Company accounts for its investments in Equion and TSEUK using the equity method of accounting. All reserves, production and other operating data reported herein which includes information relating to Equion and TSEUK, reflects the Company’s 49% equity interest in Equion and the Company’s 51% equity interest in TSEUK.
All dollar amounts in this Annual Information Form are presented in US dollars, except where otherwise indicated.
Readers are directed to the “Forward-Looking Information” section contained in the Advisories in this Annual Information Form.
CORPORATE STRUCTURE
The Company is an upstream oil and gas company wholly-owned by a subsidiary of its ultimate parent company, Repsol. It is incorporated under the Canada Business Corporations Act and its registered and head office is located at Suite 2000, 888 — 3rd Street SW, Calgary, Alberta, T2P 5C5.
The following table lists the material operating subsidiaries owned directly or indirectly by the Company, their jurisdictions of incorporation and the percentage of voting securities beneficially owned, controlled or directed by the Company as at December 31, 2015.
Name of Subsidiary | | Jurisdiction of
Incorporation/Formation | | Percentage of Voting
Securities Owned(1) | |
Repsol Canada Energy Partnership(2) | | Alberta | | 100 | % |
Talisman Energy USA Inc. | | Delaware | | 100 | % |
Repsol Alberta Shale Partnership | | Alberta | | 100 | % |
Talisman (Corridor) Ltd. | | Barbados | | 100 | % |
Talisman (Vietnam15-2/01) Ltd. | | Alberta | | 100 | % |
Talisman Malaysia Limited | | Barbados | | 100 | % |
Talisman Malaysia (PM3) Limited | | Barbados | | 100 | % |
Talisman (Algeria) B.V. | | The Netherlands | | 100 | % |
Talisman Wiriagar Overseas Limited | | British Virgin Islands | | 100 | % |
(1) None of the subsidiaries listed in the above table have any non-voting securities outstanding.
(2) Repsol Canada Energy Partnership, formerly Talisman Energy Canada, is an Alberta general partnership which currently carries on substantially all of the Company’s conventional Canadian oil and gas operations.
The above table does not include all of the subsidiaries of the Company. The assets, sales and operating revenues of unnamed operating subsidiaries individually did not exceed 10% and, in the aggregate, did not exceed 20% of the total consolidated
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assets or total consolidated sales and operating revenues, respectively, of the Company, as at and for the year ended December 31, 2015.
GENERAL DEVELOPMENT OF THE BUSINESS
General
The Company’s main business activities include exploration, development, production, transportation and marketing of crude oil, natural gas and natural gas liquids.
For the purposes of financial reporting, the Company’s 2015 activities were conducted in four geographic segments: North America, Southeast Asia, North Sea, and Other. The North America segment includes operations and exploration activities in Canada and the US. The Southeast Asia segment includes operations and exploration activities in Indonesia, Malaysia, Vietnam and Papua New Guinea, and operations in Australia/Timor-Leste. The North Sea segment includes operations and exploration activities in the UK. As at year-end 2015, the Company also has operations in Algeria, operations and exploration activities in Colombia and exploration activities in the Kurdistan Region of Iraq. For ease of reference, activities in Algeria, Colombia, the Kurdistan Region of Iraq and Peru (which the Company is in the process of exiting), are referred to collectively as the “Other” geographic segment or “Rest of World”, except where otherwise noted.
This Annual Information Form aligns with the Company’s geographic segments for the purposes of financial reporting.
Three-Year History
The Company began upstream oil and gas operations in 1992 and built its portfolio of assets through a combination of exploration, development and acquisitions.
In 2013, in furtherance of new strategic priorities established by the Company’s board of directors (the “Board”) in 2012, the Company commenced a program involving the sale of non-core assets that were generating little or no short-term cash flow and the cessation of activities in certain countries. During that year, the Company’s senior management team, conducted an in-depth review of the Company’s strategy and business and reported regularly to the Board on the challenges and the progress of the review. In February 2014, the Company announced the planned disposition of additional assets in the following 12 to 18 months, primarily focused on long-dated and/or capital intensive assets outside of North America and Southeast Asia.
Throughout 2014, the Company pursued various potential asset dispositions, including transactions involving its Marcellus midstream assets, certain mature Canadian assets, its Duvernay assets (Canada), assets in Southeast Asia, and assets in Norway and the Kurdistan Region of Iraq. The Company completed the sale of 75% of its dry gas Montney position for C$1.5 billion to Progress Energy Canada Limited in 2014. During 2014, the Company had various discussions with other parties which culminated in the Repsol Transaction described below.
During 2015, the Company completed additional dispositions. On September 1, 2015, the Company completed the sale of all of the assets and liabilities of the Company’s Norwegian operations to Repsol Exploration Norge AS, a subsidiary of Repsol. In December 2015, the Company agreed to sell its 50% interest in Block CPE-6 located in Colombia to Meta Petroleum Corporation, a subsidiary of Pacific Exploration & Production Corp. This transaction is subject to certain closing conditions and regulatory approvals, and is expected to close in 2016. On December 30, 2015, the Company completed the sale of 26% (being a net 13% working interest) of its interests in the Eagle Ford area of southeast Texas to certain subsidiaries of Statoil ASA (“Statoil”). As part of this transaction, the Company also agreed to amend the South Texas Joint Development Agreement with Statoil and transfer operatorship of that portion of the Eagle Ford operated by the Company to Statoil.
Repsol Transaction
On December 15, 2014, the Company entered into an arrangement agreement with Repsol and an indirect wholly-owned subsidiary of Repsol providing for Repsol’s acquisition of the Company (the “Repsol Transaction”) by way of an arrangement under the Canada Business Corporations Act. On May 8, 2015, the Repsol Transaction was completed. Repsol acquired all of the Company’s outstanding common shares (“Common Shares”) and preferred shares. Upon the completion of the Repsol Transaction, the Common Shares were delisted from the Toronto Stock Exchange and the New York Stock Exchange, and the preferred shares were delisted from the Toronto Stock Exchange and subsequently converted into Common Shares.
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On January 1, 2016, the Articles of the Company were amended to change the name of the Company from Talisman Energy Inc. to Repsol Oil & Gas Canada Inc.
DESCRIPTION OF THE BUSINESS
General
The Company’s aggregate production from its consolidated entities and equity investments for the year ended December 31, 2015 was 372 mboe/d, comprised of 42 mbbls/d of oil and liquids and 797 mmcf/d of gas from North America; 36 mbbls/d of oil and liquids and 483 mmcf/d of gas from Southeast Asia; 29 mbbls/d of oil and liquids and 18 mmcf/d of gas from the North Sea; and 26 mbbls/d of oil and liquids and 42 mmcf/d of gas from other areas. Approximately 36% of the Company’s production is liquids and 64% is natural gas (on a 5.615 mcf:1 bbl equivalency basis).
North America
The Company’s North America operations are organized into two distinct businesses: Canada and United States. The Company has operations in the Greater Edson (oil and gas production), Duvernay (liquids rich shale gas) and Chauvin (heavy oil production) areas, located in the Western Canadian Sedimentary Basin, primarily in Alberta, Canada; the Eagle Ford liquids-rich, shale gas play located in southeast Texas; and the Marcellus dry gas shale play located in northeast Pennsylvania. In 2015, North America production accounted for 50% of total Company production. As at December 31, 2015, the Company operated approximately 80% of its North America production.
Canada
The Company’s Canadian interests are focused around liquids and gas opportunities in the Greater Edson area of Alberta, conventional heavy oil in the Chauvin area of Alberta/Saskatchewan and liquids-rich gas in Alberta’s Duvernay play. The Company spent approximately $353 million to explore and develop its assets in Canada in 2015, resulting in total production of 61 mboe/d. In 2016, the Company plans to continue to develop land positions in Greater Edson, Chauvin and Duvernay. The Company holds approximately 1.1 million net acres of land in Western Canada. The Company’s operations include four operated gas plants in the Edson area and an oil treatment facility in Chauvin, and extensive oil and gas gathering facilities in both Edson and Chauvin.
Greater Edson
The Company’s Greater Edson assets are primarily located in the liquids and gas formations in the Edson area of Alberta and Groundbirch area of British Columbia. The Company continued to develop its Greater Edson assets throughout 2015 with exploration and development spending of $163 million, resulting in total production of 270 mmcfe/d (48 mboe/d), which represents 79% of total Canadian production. In total, 41 gross (29 net) wells were drilled in 2015. The Company holds approximately 561,000 net acres in the Greater Edson area.
Chauvin
In the Chauvin area of Alberta/Saskatchewan, production for 2015 was 11 mboe/d (95% heavy oil), which represents 18% of total Canada production. A total of 21 infill wells (15 horizontal producers, 5 injectors and 1 stratigraphic test well) were drilled in 2015. The Company holds approximately 129,000 net acres in the Chauvin area.
Duvernay
In the liquids-rich Duvernay play in west-central Alberta, the Company currently holds interests in approximately 329,000 net acres of land. During 2015, the Company drilled 8 horizontal wells in the Duvernay play. Total production in 2015 was 11 mmcfe/d (2 mboe/d), representing 3% of total Canada production.
United States
The Company has interests in two shale gas plays in the United States - a dry shale gas play in the Marcellus and a liquids-rich shale gas play in the Eagle Ford. In 2015, the Company spent approximately $465 million on exploration and development in respect of these shale gas plays. Production from these plays totaled approximately 124 mboe/d in 2015.
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Marcellus Shale
The Company’s interests in the Marcellus shale play are located in New York and Pennsylvania. The Company’s main area of focus in 2015 was in Pennsylvania. At year-end, the Company’s full year production in the Marcellus shale play averaged 490 mmcf/d (100% gas), which represents 47% of the Company’s total North America production. In total, 36 gross (34 net) wells were put on-stream in 2015, the majority of which were in the Friendsville area in conjunction with associated infrastructure build-out. During 2015, the Company acquired 9,429 net acres of undeveloped land and 9 mmcf/d of existing production located in the Chaffee area. The Company currently holds approximately 170,000 net acres of land in the Marcellus shale gas play in Pennsylvania and a 30,000 acre land position in the Utica shale play underlying the Marcellus rights.
In Pennsylvania, the Company has midstream assets consisting of approximately 300 miles of gathering/transmission pipelines serviced by eight compression/gas dehydration facilities. The pipeline system has throughput capacity of approximately 1.5 bcf/d. In 2015, these facilities delivered 490 mmcf/d into outlets on Tennessee Gas, Empire, Dominion Transmission and Corning Natural Gas pipelines. The New York midstream assets currently consist of approximately 174 miles of gathering/transmission pipelines and 4 compression/gas processing facilities with throughput capacity of 125 mmcf/d. During 2015, these facilities delivered 14 mmcf/d from the Trenton Black River formation production to facilities on the Dominion Transmission, NYSEG, Millennium and Corning Natural Gas pipelines. All of these systems currently gather mostly volumes from wells in which the Company currently has a working interest, although additional capacity is available for future use by the Company or third parties. The Company currently holds approximately 625 mmcf/d of gas pipeline take away capacity from the Marcellus area and excess pipeline capacity is mitigated when possible.
In December 2014, the New York Governor’s office announced that it was banning high volume hydraulic fracturing in New York state, following the completion of a review conducted by the state’s Department of Environmental Conservation. Also, in June 2014, the New York Supreme Court upheld the ability of local municipalities to ban hydraulic fracturing activities. The use of local ordinances (also known as “home rules”) effectively bans oil and gas operations within the municipal jurisdictional boundary. The Company has no immediate plans to drill in New York and will continue to monitor regulatory changes applicable to future operations in New York.
Eagle Ford Shale
The Company’s interests in the Eagle Ford shale play are located in southeast Texas. On December 30, 2015, the Company completed the sale of 26% (being a net 13% working interest) of its interests in the Eagle Ford to certain subsidiaries of Statoil. As part of this transaction, the Company also agreed to amend the South Texas Joint Development Agreement with Statoil and transfer operatorship of the western portion of the Eagle Ford to Statoil. As a result, the Company now holds a net 37% working interest in the play comprising approximately 41,700 net acres of land.
The Company’s full year production in the Eagle Ford averaged 34 mboe/d (24% natural gas liquids and 33% oil), which represents 18% of total North America production. In total, 60 gross (27 net) joint venture wells and 75 gross (4 net) third party non-operated wells were drilled in 2015.
Southeast Asia
The Company has interests in Indonesia, Malaysia, Vietnam, Australia/Timor Leste and Papua New Guinea. In 2015, Southeast Asia production averaged 122 mboe/d, which accounted for approximately 33% of the Company’s production worldwide. As at year-end 2015, the Company operated approximately 45% of its Southeast Asia production.
Indonesia
The Company’s Indonesian assets include interests in production sharing contracts (“PSCs”) at Corridor, Ogan Komering and Jambi Merang in South Sumatra and in the Tangguh LNG project in West Papua. The Company also holds exploration acreage, including the Sakakemang and Andaman III PSCs in South and North Sumatra, respectively. During the year, the Company was awarded two Joint Study Agreements. The Company also has an indirect, 6% interest in the Grissik-to-Duri pipeline and the Grissik-to-Singapore pipeline which is used to transport gas from the Corridor PSC. In 2015, the Company finalized the East Jabung farm-in agreement, which gives the Company 51% operatorship of the PSC. The Company also relinquished its interests in the remaining three of four PSCs in the Makassar Straits during the year.
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In the Corridor PSC, the Company has a 36% non-operated interest in all but two of the producing fields, the exceptions being the Gelam and Suban fields which are unitized with adjoining blocks, where the Company’s unit interests are 30.96% and 32.4%, respectively.
The majority of the Company’s natural gas production from the Corridor block is currently sold under long-term sales agreements with PT Chevron Pacific Indonesia, Gas Supply Pte. Ltd. and PT Perusahaan Gas Negara (Persero), Tbk. (“PGN”). Gas sales from Corridor to PGN for their markets in West Java are sold under a long term contract with no associated transportation costs. During the year, the Company entered into three gas sales agreements related to the Corridor PSC.
In 2015, net production to the Company from the Corridor PSC was approximately 59 mboe/d. Corridor production accounted for approximately 48% of the Company’s Southeast Asia production. In 2015, two out of the three wells in the Suban drilling campaign (Suban-14 and Suban-13) were completed and brought on stream. In 2015, production from the Company’s 25% interest in the Jambi Merang PSC averaged 4.7 mboe/d.
The Company’s share of production from the Tangguh LNG project contributed 5.6 mboe/d in 2015.
In 2015, the Company drilled two step-out development wells in the Ogan Komering Block and continued the 2D and 3D seismic acquisition program in Sakakemang.
Malaysia
The Company holds a 41.44% operated interest in Block PM-3 CAA PSC between Malaysia and Vietnam and associated production facilities. In addition, the Company holds a 70% interest in Block 46-Cai Nouc adjacent to PM-3 CAA and a 60% interest in each of Block PM-305 and Block PM-314.
In Block PM-3 CAA, the Company operates facilities referred to as the “Southern Fields” and the “Northern Fields”. Licenses in the PM-3 CAA are currently subject to negotiations for renewal. In addition, the Company also completed infill drilling in the Southern Fields during the year. Production from PM-3 CAA averaged 31 mboe/d in 2015.
The Company holds a 70% working interest in the exploration Block SB309, offshore Sabah in east Malaysia. The Company drilled the final commitment well on Block SB309 in 2015. Upon completion of the drilling program, an 8 month extension, to June 2016, was granted on Block SB309, to provide the Company with adequate time to fully assess the results of the final exploration well. During the year, the Company successfully completed a farmdown of its interest in the adjoining Block SB310, to SapuraKencana Energy Sabah Inc., thereby reducing its working interest to 35%.
The Company holds a 60% equity interest and operatorship of the Kinabalu Oil PSC, which is a mature offshore oilfield in the Malaysian Sabah Basin. In 2015, the Company successfully completed several preventative maintenance and intervention programs. The Kinabalu redevelopment project, consisting of a wellhead platform bridge linked to the existing Kinabalu facilities and ten oil production wells, was sanctioned in July 2015. The Company also relinquished its associated gas rights back to Petronas effective April 1, 2015. Production from Kinabalu averaged approximately 6.4 mboe/d in 2015.
In 2015, the Company’s net share of production in Malaysia averaged 39 mboe/d, which accounted for approximately 32% of the Company’s total Southeast Asia production.
Vietnam
The Company holds a 60% interest in Block 15-2/01 as a partner in the Thang Long Joint Operating Company, which operates the Block. Block 15-2/01 lies in the Cuu Long Basin, the predominant oil producing basin in Vietnam. The Company holds a 49% operated interest in Blocks 133 and 134, a 40% operated interest in Blocks 135 and 136, a 40% operated interest in Block 05-2/10, a 46.75% operated interest in Block 07/03, including the Red Emperor discovery, adjacent to Blocks 135 and 136 in the Nam Con Son basin, and an 80% operated interest in Blocks 146 and 147. In 2015, the Company entered into a Transfer Agreement with ExxonMobil to assume 100% operated interest in Blocks 156-159, (east of Blocks 133-136) for no financial consideration.
Combined production from the Company’s interest in the HST/HSD project, situated in Block 15-2/01, and its interest in the adjacent TGT Unit, averaged 9 mboe/d in 2015, accounting for approximately 7% of the Company’s total Southeast Asia production. During the year, the Company spudded the HSD-6P well which is now being assessed for design modifications in order for drilling to start back up in 2016. The CRD discovery in Block 07/03 was declared commercial during the year. In addition, a 3D seismic program was successfully completed over the COBIA region in Block 07/03.
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Australia/Timor-Leste
The Company holds non-operated interests in the Laminaria (33%) and Corallina (40%) fields offshore Australia. The Company’s net production in Australia/Timor-Leste averaged 2.5 mboe/d in 2015.
In September 2015, a wholly-owned subsidiary of the Company entered into a sale agreement pursuant to which it will sell its shareholdings in another subsidiary which in turn holds license interests in the Laminaria and Corallina fields and an interest in the Northern Endeavour FPSO. This transaction is subject to receipt of all necessary regulatory approvals.
The Company is continuing to work with potential buyers to divest its 25% interest in the Kitan project (JPDA 06-105).
Papua New Guinea
In Papua New Guinea, the Company continues with its gas aggregation strategy with partners Santos Ltd. and Mitsubishi Corporation. In 2015, the Company successfully completed two seismic programs in PPL269.
North Sea
Subsequent to September 1, 2015, the Company’s North Sea business consists of its equity investment in TSEUK in the United Kingdom. In aggregate, the Company’s North Sea business delivered total production of 32 mboe/d in 2015.
Norway
On September 1, 2015, the Company completed the sale of substantially all of the assets and liabilities of the Company’s Norwegian operations to Repsol Exploration Norge AS (“RENAS”), a subsidiary of Repsol. Prior to this sale, the Company operated the Blane, Gyda, Rev, Yme and Varg fields with interests ranging from 18% to 70% during 2015. It also held interests from 10% to 34% in a number of non-operated fields with associated production facilities and intrafield pipelines including, Brage, Veslefrikk, Brynhild and Tambar East.
In 2015, prior to completing the sale to RENAS, the Company participated in the unsuccessful Snømus and Crossbill exploration wells, and participated in the completion of three development wells.
Until September 1, 2015, production in Norway averaged 17 mboe/d, based on 243 days of production (11 mboe/d based on 365 days of production) across 8 fields. The primary focus in Norway was oil, with oil and liquids contributing to 78% of the Company’s Norway production.
United Kingdom
The Company holds a 51% equity interest in TSEUK. The remaining 49% is held by Addax Petroleum UK Limited, a wholly-owned subsidiary of the Sinopec Group. TSEUK is governed through its Executive Committee and Board of Directors. The Executive Committee, comprised of shareholder representatives, is the primary decision-making body for items beyond the authority limit of TSEUK’s management team. TSEUK’s Board of Directors, comprised of an equal number of shareholder representatives plus an independent director, is the decision-making body for items beyond the authority limit of the Executive Committee. As a shareholder, the Company does not have control of the day-to-day operations of TSEUK.
TSEUK
The Company’s share of capital investment in exploration and development activities during 2015 was $337 million. The Company’s investment in TSEUK contributed 21 mboe/d. At year-end, TSEUK operated approximately 92% of its production.
TSEUK’s principal operating areas encompass a total of 42 fields in the UK, 32 of which are operated and 10 of which are non-operated. TSEUK’s working interests in fields range from 5% to 100%. TSEUK also has interests in production facilities and pipelines, including a 100% interest in the Flotta Terminal. Pursuant to the TSEUK shareholders’ agreement, the Company agreed to spend up to $2.5 billion over five years (2012-2016), on projects that meet a prescribed economic threshold. Of this amount, the Company expects to spend approximately $0.3 billion over the coming year.
During 2015, production was reinstated following extended outages at the Montrose, Arbroath, Tartan and Scapa fields. First oil from the Godwin well was achieved in the third quarter of 2015. TSEUK continued to make progress on the Montrose Area Redevelopment project, which was sanctioned in 2012. The project is expected to deliver first oil in the second quarter
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of 2017, with peak production currently expected in 2018. 72% of the project was complete as at year-end. The Seagull exploration well was tested in the third quarter of 2015 with evaluation of the results currently ongoing. Hand back of the Beatrice field following the conclusion of a 2008 lease agreement with a third party was completed in the first quarter of 2015 with preparations for decommissioning the field underway.
Rest of World
The Company’s other interests as at December 31, 2015 include non-operated production and exploration activities in Colombia, non-operated production in Algeria and exploration activities in the Kurdistan Region of Iraq.
Colombia
This section describes the Company’s own operations in Colombia. Operations relating to the Company’s 49% interest in Equion, accounted for using the equity method, are described in a separate section below.
The Company currently holds an interest in 4.246 million net acres (excluding the acreage owned by Equion) in Colombia.
In Block CPO-9, 2015 production averaged 3 mboe/d. The Nueva Esperanza-2 and Nueva Esperanza-3 wells were completed in 2015. A long term testing permit for these wells was awarded in June. Regulatory approval for the exploitation license for the Akacias field in block CPO-9 was given in October 2015, allowing for the start of a drilling campaign in 2016.
The Company agreed to sell its 50% interest in Block CPE-6 in December to Meta Petroleum Corporation, a subsidiary of Pacific Exploration & Production Corp. This transaction is subject to a number of closing conditions and regulatory approvals and it is expected to close in the second quarter of 2016.
In Block CPE-8, the force majeure application expired in September 2015 and the license is now set to expire during the third quarter of 2016.
In 2015, regulatory approval was given to the Company to transfer a 50% interest in the Putamayo-30 block to Amerisur Resources PLC.
In the Foothills region, an application to extend the evaluation period of the Niscota block was submitted to regulatory authorities due to delays in receiving the environmental license for development activity. The Payero exploration well was spudded in December 2015, and is estimated to finish drilling in the second quarter of 2016.
Equion
The Company holds a 49% equity interest in Equion. The remaining 51% interest is held by Ecopetrol S.A. Equion currently holds upstream licenses in a number of blocks and also holds equity and capacity interests in three pipelines. 2015 production averaged 19 mboe/d.
During 2015, Equion completed five development wells, with two additional wells spudded in the second quarter of 2015, and targeted for completion by the second quarter of 2016. Stage 2 of the Floreña Facilities expansion was completed during the fourth quarter of 2015.
Algeria
The Company holds a 35% non-operated interest in Block 405a under a PSC with Algeria’s national oil company, Sonatrach. Through its participation in Block 405a, the Company currently holds a 35% interest in the producing Greater Menzel Lejmat North (“MLN”) fields and the Menzel Lejmat Southeast field, a 2% interest in the producing unitized Ourhoud field, and a 9% interest in the unitized EMK field produced through the El Merk facility. The Company’s Algeria production is 100% liquids.
Production from the area averaged 10.8 mboe/d in 2015. During 2015, two wells were drilled in the EMK field, while regulatory approval for a development plan to increase production in MLN was granted in September, 2015.
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The Kurdistan Region of Iraq
The Company has an interest in two blocks, Kurdamir and Topkhana, in the Kurdistan Region of Iraq covering approximately 120,000 net acres.
The Company submitted a notice of withdrawal from the Joint Operating Agreement (“JOA”) on the Kurdamir Block to its partner WesternZagros Resources Ltd. (“WesternZagros”) in December 2014. The Company retracted its notice of withdrawal in March 2015 following the Kurdistan Regional Government’s (“KRG”) rejection of the assignment by the Company to WesternZagros of the Company’s participating interests in the Kurdamir PSC. The effect of the Company’s retraction of the notice of withdrawal is that the Company remains party to the JOA and PSC and remains operator of the Kurdamir Block.
The Company submitted the Declaration of Commercial Discovery and the Appraisal Report on the Topkhana Block to the KRG in late 2015. The Company is working on submitting a suitable development plan with partner WesternZagros and the KRG on the Kurdamir Block, as well as a suitable development plan with the KRG on the Topkhana Block.
RESERVES AND OTHER OIL AND GAS INFORMATION
Information on the Company’s reserves and other oil and gas information, prepared in accordance with Canadian disclosure requirements, is set forth in Schedule A.
COMPETITIVE CONDITIONS
The oil and gas industry, both within North America and internationally, is highly competitive in all aspects of the business. The Company actively competes for the acquisition of properties, the exploration for and development of new sources of supply, the contractual services for oil and gas drilling and production equipment and services, the transportation and marketing of current production, and industry personnel. With respect to the exploration, development and marketing of oil and natural gas, the Company’s competitors include major integrated oil and gas companies, numerous other independent oil and gas companies, individual producers and operators, and national oil companies. A number of the Company’s competitors have financial and other resources substantially in excess of those available to the Company. However, as part of the larger Repsol integrated oil and gas group, the Company has greater access to additional financial and other resources than previously available. In addition, oil and gas producers in general compete indirectly against others engaged in supplying alternative forms of energy, fuel and related products to consumers.
CORPORATE RESPONSIBILITY AND ENVIRONMENTAL PROTECTION
Corporate Policies
The Company has adopted a Code of Business Conduct and Ethics (the “CBCE”) which is applicable to all directors, officers, and employees of the Company, and independent contractor workers to the extent that they conduct activities on the Company’s behalf. To monitor compliance with the CBCE, certificates are required at least annually from all directors, worldwide employees and various consultants of the Company, which confirm compliance with the CBCE or disclose any deviations therefrom. The Company requires annual online ethics training as part of the certificate of compliance process. Exceptions are required to be noted directly to the Chief Executive Officer, and supervisors are notified if employees do not complete their annual certifications. Disclosures contained in the certificates, as well as a status report on the percentage of directors, employees and various consultants who have completed their annual certification, are reported to the Audit Committee of the Board for consideration. The Board reviews any requests for waivers from the CBCE from executive officers and directors, and all material waivers from the CBCE are required to be disclosed promptly to the Company’s shareholder, Repsol. No waivers from the CBCE were granted for the benefit of the Company’s executive officers or directors during the year ended December 31, 2015.
The Company values good faith actions in support of the CBCE and will not tolerate retaliation of any kind as a result of good faith reporting by employees. The Company requires that observed breaches of the CBCE be reported to a supervisor or manager, a Vice President in the Legal Department, the Director, Audit & Control North America, an executive officer, or through the Company’s Integrity Matters hotline.
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Health, Safety and Environmental Protection
The Board of Directors and all executive officers oversee and are accountable for the Company’s health, safety, security, environment and operational performance. The Company’s Board and the Company’s executive officers regularly review policies, management systems, internal controls, performance reports, significant issues, exposures and strategic initiatives in the area of health, safety and the environment (“HSE”).
In 2013, the Company introduced a new Global Standard for Safe Operations (the “Global Standard”), and associated mandatory practices, effective January 31, 2014. The Global Standard provides for a systematic approach to managing key risks related to occupational health, environment, personal safety and process safety.
The Global Standard defines the Company’s minimum expectations for safe operations in each of the following areas: leadership commitment and accountabilities; regulatory compliance; risk management; capability and training; contractor HSE management; asset design and construction; safe operations; operations and integrity management; management of change; emergency and crisis management; incident reporting, investigation and analysis; information and documentation; and reporting, assurance and review. At the Company, respective country or business unit leaders are required to base the development and implementation of local management systems upon the Global Standard. In 2015, after the closing of the Repsol Transaction, the Company initiated an integration process with Repsol on HSE matters. Repsol has a global HSE management system standard that is closely aligned with the Company’s Global Standard. The Company’s HSE standards and processes remain in place and are applicable during the integration period.
Safe operations in all Company activities form a core value of the Company. If operational results and safety ever come into conflict, the Company’s employees and contractors are empowered and encouraged to choose safety over operational results. The Company will support that choice. The Company’s safety culture is driven by strong commitment from senior management and safety accountability at all levels of the organization.
The Company regularly reports to and consults with government agencies in its operating regions and submits to routine regulatory inspections. The Company also conducts environmental due diligence on applicable asset and corporate acquisitions to identify and properly account for pre-existing environmental liabilities.
EMPLOYEES
At December 31, 2015, the Company’s permanent staff complement (excluding employees of TSEUK and Equion) was 2,302, as set forth in the table below.
| | Permanent Staff Complement(1)
as at December 31, 2015 | |
North America | | 1,398 | |
North Sea | | 2 | |
Southeast Asia | | 823 | |
Rest of World(2) | | 79 | |
Total | | 2,302 | |
(1) Contractors and temporary staff are not included in complement numbers.
(2) Rest of World refers to Algeria, Colombia, the Kurdistan Region of Iraq and the Company’s regional finance offices.
DESCRIPTION OF CAPITAL STRUCTURE
Share Capital
The Company’s authorized share capital consists of an unlimited number of Common Shares without nominal or par value and an unlimited number of first and second preferred shares. The outstanding shares consist of Common Shares. Upon the completion of the Repsol Transaction, Repsol acquired all of the Company’s outstanding Common Shares and then outstanding first preferred shares. The outstanding first preferred shares were subsequently converted to Common Shares.
Ratings
The following information relating to the Company’s credit ratings is provided as it relates to the Company’s financing costs, liquidity and cost of operations. Specifically, credit ratings impact the Company’s ability to obtain externally sourced short-term and long-term financing and the cost of such financings. A negative change in the Company’s ratings outlook or any downgrade in the Company’s current investment-grade credit ratings by its rating agencies, particularly below investment
9
grade, could adversely affect its cost of borrowing and/or access to sources of liquidity and capital. In addition, changes in credit ratings may affect the Company’s ability to enter into, or the associated costs of entering into, ordinary course contracts on acceptable terms, and a decline in the credit ratings or outlook may require the Company to post collateral or post additional collateral under certain of its contracts. The following table outlines the ratings assigned to the Company by credit rating agencies as at December 31, 2015.
| | Standard & Poor’s
Rating Services
(“S&P”) | | Moody’s Investors
Services
(“Moody’s”) | | Fitch Rating
Services
(“Fitch”) | |
Senior Unsecured/Long-Term Rating | | BBB– | | Baa3 | | BBB– | |
US Commercial Paper/Short-Term Rating | | A-3 | | P-3 | | F3 | |
Outlook/Trend | | Negative | | Negative | | Stable | |
Credit ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities and are indicators of the likelihood of payment and of the capacity of a company to meet its financial commitment on the rated obligation in accordance with the terms of the rated obligation. The ratings agencies regularly evaluate the Company, and their ratings of the Company’s securities are based on a number of factors not entirely within the Company’s control, including conditions affecting the oil and gas industry generally, and the wider state of the economy. The credit ratings assigned to the Company’s senior unsecured long-term debt securities and the Company’s US commercial paper (“US Commercial Paper”) are not recommendations to purchase, hold or sell the securities and may be revised or withdrawn entirely at any time by a rating agency. Credit ratings may not reflect the potential impact of all risks or the value of these securities. In addition, real or anticipated changes in the rating assigned to the securities will generally affect the market value of the securities. There can be no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.
S&P’s credit ratings are on a long-term debt rating scale that ranges from AAA to D, representing the range from highest to lowest quality of such securities rated. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories. The BBB rating category is the fourth highest of the eleven major ratings categories used by S&P. According to S&P’s rating system, debt securities rated BBB- are considered the lowest investment grade by market participants.
S&P’s credit rating for short-term issues range from A-1 to D, representing the range from highest to lowest quality of such securities rated. According to S&P, a short-term obligation rated A-3 exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation.
Moody’s long-term debt credit ratings are on a scale that ranges from Aaa to C, representing the range from least credit risk to greatest credit risk of such securities rated. Moody’s applies numerical modifiers 1, 2 and 3 in each generic rating classification from Aa through Caa in its long-term debt rating system. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue ranks in the lower end of that generic rating category. According to the Moody’s rating system, debt securities rated within the Baa category are subject to moderate credit risk. They are considered medium grade and, as such, may possess certain speculative characteristics.
Moody’s short-term debt ratings are on a scale of P-1 to NP, representing the range from least credit risk to greatest credit risk of such securities rated. Short-term ratings are opinions of the ability of issuers to honour short-term financial obligations, typically with an original maturity not exceeding 13 months. According to Moody’s rating system, issuers rated P-3 have an acceptable ability to repay short-term obligations.
Fitch’s long-term debt credit ratings are on a scale that ranges from AAA to RD/D, representing the range from highest to lowest quality of such securities rated. The BBB rating category is the fourth highest of the eleven major ratings categories used by Fitch. According to Fitch’s rating scale, obligations rated BBB are of good credit quality, expectations of default risk are low and the capacity for payment of financial commitments is considered adequate but adverse business or economic conditions are more likely to impair this capacity. The modifiers “+” or “–” may be appended to a rating to denote relative status within major rating categories.
Fitch’s short-term credit ratings are on a scale that ranges from F1 to D, representing the range from highest to lowest quality of such securities rated. According to Fitch’s rating scale, obligations rated F3 are of fair credit quality and have adequate intrinsic capacity for timely payment of financial commitments.
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Subsequent to December 31, 2015, on January 22, 2016, Moody’s placed the Company’s Baa3 bond ratings on review for downgrade and on February 1, 2016, S&P placed the ratings on the Company on CreditWatch with negative implications.
MARKET FOR THE SECURITIES OF THE COMPANY
Subsequent to the closing of the Repsol Transaction, the Common Shares of the Company were delisted on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange and the Company’s Series 1 First Preferred Shares were de-listed from the TSX. The Company’s UK£250 million 6.625% Notes are listed on the London Stock Exchange.
Dividends
On April 29, 2015, the Company paid a dividend on the Company’s Common Shares totaling US$0.1125 per share. The Company does not have a specific dividend policy and the declaration of dividends on the Common Shares is at the sole discretion of its Board of Directors. On March 31, 2015, the Company paid a dividend on the Company’s Series 1 First Preferred Shares totaling C$0.2625 per Series 1 First Preferred Share.
The Company confirms that all dividends paid to shareholders in 2015 are “eligible dividends” pursuant to provisions of the Income Tax Act (Canada).
The Company paid the following dividends on its Common Shares over the last three years:
Date | | Rate Per
Common Share | |
March 28, 2013 | | US$ | 0.0675 | |
June 28, 2013 | | US$ | 0.0675 | |
September 30, 2013 | | US$ | 0.0675 | |
December 31, 2013 | | US$ | 0.0675 | |
March 31, 2014 | | US$ | 0.0675 | |
June 30, 2014 | | US$ | 0.0675 | |
September 30, 2014 | | US$ | 0.0675 | |
December 31, 2014 | | US$ | 0.0675 | |
April 29, 2015 | | US$ | 0.1125 | |
The Company paid the following dividends on its Series 1 First Preferred Shares over the last three years:
Date | | Rate Per Series 1
First Preferred Share | |
April 1, 2013 | | C$ | 0.2625 | |
July 2, 2013 | | C$ | 0.2625 | |
September 30, 2013 | | C$ | 0.2625 | |
December 31, 2013 | | C$ | 0.2625 | |
March 31, 2014 | | C$ | 0.2625 | |
June 30, 2014 | | C$ | 0.2625 | |
September 30, 2014 | | C$ | 0.2625 | |
December 31, 2014 | | C$ | 0.2625 | |
March 31, 2015 | | C$ | 0.2625 | |
DIRECTORS AND OFFICERS
Information is given below with respect to each of the current directors and officers of the Company.
Directors
The directors of the Company are elected annually. The following table sets out the name, city, province or state and country of residence, year first elected or appointed to the Board of Directors, principal occupation within the past five years or more, educational qualifications and other current directorships of each of the directors of the Company as at December 31, 2015.
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Name, City, Province or
State and Country of Residence | | Year First
Became
Director
of the
Company | | Present Principal Occupation or Employment (including all officer positions currently
held with the Company), Principal Occupation or Employment for the Past Five Years or
More, Educational Qualifications, Other Current Public Company Directorships or
Directorships in Non-Public Companies, Organizations or other Entities that Require a
Significant Time Commitment |
Albrecht W.A. Bellstedt(1)
Calgary, Alberta
Canada | | 2015 | | Albrecht Bellstedt has been a professional director since February 2007. Previously (and from 1999 to 2007), Mr. Bellstedt served as Executive Vice-President and General Counsel of TransCanada Corporation and a predecessor corporation. Prior to that, he was a transactional lawyer in private practice for 27 years. Mr. Bellstedt holds a Juris Doctor from the University of Toronto and a Bachelor of Arts degree from Queen’s University.
Current public company directorships(2): Canadian Western Bank, Capital Power Corporation and Stuart Olson Inc.
Other current directorships(3): None
|
Tomás García Blanco
Madrid, Spain | | 2015 | | Tomás García Blanco is Executive Director, Europe, Africa and Brazil of Repsol. He joined Repsol in 1990 and since held several positions in Repsol, Repsol Exploración, S.A., & YPF., Previously (and from 2010 to 2015) he was VP Upstream YPF, CEO of Repsol Sinopec Brazil; Executive Director for USA, Trinidad & Brasil and Executive Director for Europe, Africa & Brazil. Mr García Blanco has extensive international exploration and production experience working in Spain, the United States, Egypt, Libya, Venezuela, Bolivia, Brazil and Argentina. Mr. García Blanco holds a degree in mining engineering from Oviedo University (Spain), a certificate in petroleum engineering from OGCI, (Tulsa, Oklahoma) and Corporate Management Resources from the Institute of Management Development, Laussane (Switzerland).
Current public company directorships(2): None
Other current directorships(3): None
|
Luis Cabra Dueñas
Madrid, Spain | | 2015 | | Luis Cabra has served as Repsol’s Executive Managing Director of Exploration and Production since May 2012 and as Chief Executive Officer of the Company since May 2015. He joined Repsol in 1984 and has since held management posts in the Refining, Technology, Engineering, Procurement and Safety and Environment areas. From September 2010 to May 2012, he served as Executive Director of Development and Production in Repsol’s Upstream Division. Mr. Cabra has represented Repsol in international associations, serving as Chairman of the Fuel Committee of the European Petroleum Industry Association, President of the European Biofuel Technology Platform as well as Member of the European Research Advisory Board. He holds a Doctorate in Chemical Engineering from the Complutense University in Madrid and has studied business management at the international centres INSEAD and IMD. He has also served as a Head Lecturer and Associate Lecturer at the Complutense University and the University of Castilla-La Mancha.
Current public company directorships(2): None
Other current directorships(3): None
|
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Name, City, Province or
State and Country of Residence | | Year First
Became
Director
of the
Company | | Present Principal Occupation or Employment (including all officer positions currently
held with the Company), Principal Occupation or Employment for the Past Five Years or
More, Educational Qualifications, Other Current Public Company Directorships or
Directorships in Non-Public Companies, Organizations or other Entities that Require a
Significant Time Commitment |
Javier Sanz Cedrόn
Madrid, Spain | | 2015 | | Javier Sanz Cedrόn is Director of Financial Development and Rating Agencies of Repsol. He joined Repsol in 1984 in the Internal Auditing department and has since held several positions in Accounting & Reporting, International Commerce and Finance. In April 1998 he was appointed Financing Director and in 2006, he was appointed Director of Finance. Mr. Sanz Cedrόn holds a degree in Economics and Business Administration from the Comillas University — ICADE (Madrid). Following university he completed postgraduate courses at the Bank of Spain and in universities at Oxford, Brussels and Paris. Current public company directorships(2): None Other current directorships(3): None |
Thomas W. Ebbern(1)
Calgary, Alberta
Canada | | 2013 | | Thomas Ebbern has been Chief Financial Officer of North West Upgrading Inc. since January 2012. He was formerly Managing Director, Investment Banking, of Macquarie Capital Markets Canada Ltd., a subsidiary of Macquarie Group Limited. Prior to that he was Managing Director of Tristone Capital Inc., an energy advisory firm that was acquired by Macquarie. He began his career as a geophysicist with Gulf Canada in 1982. Mr. Ebbern holds a Bachelor of Science degree in Geological Engineering from Queen’s University and a Master of Business Administration from the Richard Ivey School of Business at the University of Western Ontario.
Current public company directorships(2): None
Other current directorships(3): Wellspring Calgary, Palisade Capital Management Ltd., Live Out There Inc.
|
Josu Jon Imaz San Miguel
Madrid, Spain | | 2015 | | Josu Jon Imaz was named Chief Executive Officer of Repsol and member of the Corporate Executive Committee by the Board of Directors in April 2014. Mr. Imaz joined the Repsol Group in 2008 as Chairman of its subsidiary Petronor. In 2012 he joined the Repsol Executive Committee as General Director of the Industrial Area and New Energy. He began his career in research at the French Technological Center (CETIM) in Nantes, with focus on industrial (Grupo Mondragón) and business projects linked to the energy sector. Mr. Imaz was also a visiting scholar at the Harvard Kennedy School in the United States. In addition to his business activity, Mr. Imaz has served in senior political roles within the Ministry of Industry, Trade and Tourism of the Basque Government in 1999, and the executive leadership of the EAJ-PNV. He holds a Doctorate in Chemical Sciences from the University of the Basque Country and graduated from the Faculty of Chemical Sciences in San Sebastián (with excellence).
Current public company directorships(2): None
Other current directorships(3): None
|
13
Name, City, Province or
State and Country of Residence | | Year First
Became
Director
of the
Company | | Present Principal Occupation or Employment (including all officer positions currently
held with the Company), Principal Occupation or Employment for the Past Five Years or
More, Educational Qualifications, Other Current Public Company Directorships or
Directorships in Non-Public Companies, Organizations or other Entities that Require a
Significant Time Commitment |
Miguel Klingenberg Calvo
Madrid, Spain | | 2015 | | Miguel Klingenberg currently serves as Managing Director of Legal Affairs at Repsol and has been a member of the Executive Committee since May 2015. He joined Repsol as Deputy Secretary General in September 2012. Before joining Repsol, he was in private practice in several law firms, including as name partner at Hervada & Klingenberg and subsequently as partner and head of the Spanish tax practice at Freshfields Bruckhaus Deringer LLP (“Freshfields”). While at Freshfields, Mr. Klingenberg acted as managing partner of the Spanish offices between 2006 and 2010 and served in a number of the firm’s governing bodies, including the Regional Management and the CSR and Pro-Bono Committees. Miguel Klingenberg holds a law degree from Deusto University and a degree in Business Administration from ICADE.
Current public company directorships(2): None
Other current directorships(3): Thyssen-Bornemizsa Museum Foundation
|
Robert R. Rooney
Calgary, Alberta
Canada | | 2015 | | Robert Rooney is Vice-Chairman of the Company. Mr. Rooney previously served as Executive Vice-President Corporate and General Counsel of Talisman Energy Inc. from November 2008 to May 2015. Prior to that, Mr. Rooney was a partner with Bennett Jones LLP where he was a member of the Executive Committee and co-leader of the Energy & Natural Resources Group. Mr. Rooney has been a co-founder and served as a director and officer of several public and private corporations. He is a past director of Blizzard Energy Inc., Cordero Energy Inc., Temple Energy Inc., Temple Exploration Inc., Zenas Energy Corp., Resolute Energy Inc. and Equatorial Energy Inc. Mr. Rooney attended the University of Calgary, earned an LL.B from the University of Western Ontario and is a member of the Law Society of Alberta.
Current public company directorships(2): None
Other current directorships(3): Ferus Inc., RimRock Oil & Gas Inc., Canada Sports Hall of Fame, Lake Louise Ski Club
|
Michael T. Waites(1)
Vancouver, British Columbia
Canada | | 2011 | | Michael Waites was President and Chief Executive Officer of Finning International Inc. from May 2008 until his retirement from Finning in May 2013. Prior to that, Mr. Waites was Executive Vice President and Chief Financial Officer of Finning. He also served as a member of the board of directors of Finning for three years prior to his appointment as Executive Vice President and Chief Financial Officer. Prior to joining Finning in May 2006, Mr. Waites was Executive Vice President and Chief Financial Officer at Canadian Pacific Railway since July 2000, and was also Chief Executive Officer U.S. Network of Canadian Pacific Railway. Previously, he was Vice President and Chief Financial Officer at Chevron Canada Resources. Mr. Waites holds a Bachelor of Arts (Honours) in Economics from the University of Calgary, a Master of Business Administration from Saint Mary’s College of California, and a Master of Arts, Graduate Studies in Economics from the University of Calgary. He has also completed the Executive Program at The University of Michigan Business School.
Current public company directorships(2): Hudbay Minerals Inc., Western Forest Products Inc.
Other current directorships(3): Remcan Projects Limited
|
(1) Member of the Audit Committee.
(2) Refers only to issuers that are reporting issuers in Canada or the equivalent in a foreign jurisdiction.
(3) Refers to directorships of non-public companies, organizations or other entities. Does not include positions in Company subsidiaries or Repsol affiliates.
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Officers
The following table sets out the name, city, province and country of residence and office held for each of the executive officers of the Company as at December 31, 2015.
Name and Province or
State and Country of Residence | | Office |
Luis Cabra Dueñas(1)
Madrid, Spain | | Vice-Chairman and Chief Executive Officer |
David Newby (2)
Calgary, Alberta, Canada | | Senior Vice-President, Finance, Treasurer and Chief Financial Officer |
John Rossall (3)
Calgary, Alberta, Canada | | Executive Director, North America |
(1) Luis Cabra Dueñas was appointed Vice-Chairman and Chief Executive Officer on May 11, 2015.
(2) David Newby was appointed Senior Vice-President, Finance, Treasurer and Chief Financial Officer on May 11, 2015. Prior to that he was Senior Vice-President, Finance and Treasurer.
(3) John Rossall was appointed Executive Director, North America on July 7, 2015. On closing of the Repsol Transaction he was appointed Executive Director, Canada and North America Unconventional. Prior to that (from 2011 to 2015), he was Senior Vice-President, Canadian Delivery Unit, and prior to that (from 2004 to 2011), he was President and CEO of ProspEx Resources, a TSX listed junior oil and gas company.
Albrecht Bellstedt ceased being a director of Sun Times Media Group, Inc. (formerly Hollinger International Inc.) in June of 2008. Sun Times Media Group, Inc. went into Chapter 11 bankruptcy protection under the US Bankruptcy Code in 2009.
Shareholdings of Directors and Executive Officers
No director or executive officer owns, directly or indirectly, any Common Shares of the Company.
Conflicts of Interest
Certain directors of the Company and its subsidiaries are associated with other reporting issuers or other corporations, which may give rise to conflicts of interest. In accordance with the Canada Business Corporations Act, directors and officers of the Company are required to disclose to the Company the nature and extent of any interest that they have in a material contract or material transaction, whether made or proposed, with the Company, if the director or officer is: (a) a party to the contract or transaction; (b) is a director or an officer, or an individual acting in a similar capacity, of a party to the contract or transaction; or (c) has a material interest in a party to the contract or transaction. Furthermore, each director is expected to act in good faith and recuse himself or herself from such portions of Board or Board committee meetings involving any conflict between the director and the Company.
As described in “Corporate Responsibility and Environmental Protection,” the Company has adopted the CBCE, which applies to all directors, officers, employees and contractors of the Company and its subsidiaries. As required by the CBCE, individuals representing the Company must not enter into outside activities, including business interests or other employment that might interfere with or be perceived to interfere with their performance at the Company. In addition, the Company officers, employees and contractors are required to abide by an internal Conflict of Interest in Employment Policy.
AUDIT COMMITTEE INFORMATION
Information concerning the Audit Committee of the Company, as required by National Instrument 52-110, is provided in Schedule B to this Annual Information Form.
LEGAL PROCEEDINGS
From time to time, the Company is the subject of litigation arising out of the Company’s operations. Damages claimed under such litigation, including the litigation discussed below, may be material or may be indeterminate and the outcome of such litigation may materially impact the Company’s financial condition or results of operations. While the Company assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. None of these claims are currently expected to have a material impact on the Company’s financial position.
15
On July 13, 2015, Addax Petroleum UK Limited and Sinopec International Petroleum Exploration and Production Corporation, filed a Notice of Arbitration (pursuant to the Rules of the Singapore International Arbitration Centre) against the Company and Talisman Colombia Holdco Limited (“TCHL”) in connection with Addax’s purchase of 49% of the shares of TSEUK. On October 1, 2015, TEI and TCHL filed a response to the Notice of Arbitration. The parties have agreed to a hearing, expected to commence in 2018. The Company believes the claims included in the Notice of Arbitration are without merit.
In August 2012, a portion of the Galley pipeline, in which TSEUK has a 67.41% interest, suffered an upheaval buckle. In September 2012, TSEUK submitted a notification of a claim to Oleum Insurance Company (‘‘Oleum’’), a wholly-owned subsidiary of the Company. TSEUK delivered a proof of loss seeking recovery under the insuring agreement of $315 million. The documentation delivered in November 2014 by TSEUK purporting to substantiate its claim did not support a determination of coverage and Oleum sought additional information from TSEUK to facilitate final coverage determination. TSEUK has sent additional information to Oleum that is being reviewed by external counsel.
RISK FACTORS
The Company is exposed to a number of risks inherent in exploring for, developing and producing crude oil, natural gas liquids and natural gas. This section describes the important risks and other matters that could cause actual results of the Company to differ materially from those reflected in forward-looking statements and that could affect the trading price of the Company’s outstanding securities. The risks described below may not be the only risks the Company faces, as the Company’s business and operations may also be subject to risks that the Company does not yet know of, or that the Company currently believes are immaterial. Events or circumstances described below could materially and adversely affect the Company’s business, financial condition, results of operations or cash flow and the trading price of the Company’s securities could decline. The risks described below are interconnected, and more than one of these risks could materialize simultaneously or in short sequence if certain events or circumstances described below actually occur. The following risk factors should be read in conjunction with the other information contained herein and in the Consolidated Financial Statements and the related notes.
Volatility of Crude Oil, Natural Gas Liquids and Natural Gas Prices
The Company’s financial performance is highly sensitive to the prevailing prices of crude oil, natural gas liquids and natural gas. Fluctuations in these prices could have a material effect on the Company’s operations and financial condition, the value of its liquids and natural gas reserves and its level of expenditure for liquids and gas exploration and development. Prices for liquids and natural gas fluctuate in response to changes in the supply of and demand for liquids and natural gas, market uncertainty and a variety of additional factors that are largely beyond the Company’s control. The Company does not currently use derivative instruments to hedge the Company’s expected production so as to manage the impact of fluctuations in crude oil and natural gas prices. Fluctuations in crude oil and gas prices could have a material effect on the volatility of the Company’s earnings. Oil prices are largely determined by international supply and demand. Factors which affect crude oil prices include the actions of the Organization of Petroleum Exporting Countries, world economic conditions, government regulation, political stability throughout the world, the availability of alternative fuel sources, technological advances affecting energy production and consumption, and weather conditions. Approximately 59% of the natural gas prices realized by the Company are affected primarily by North American supply and demand, weather conditions and prices of alternative sources of energy. The remaining 41% of natural gas prices realized by the Company are in markets outside of North America, primarily in Southeast Asia. These other prices are largely determined by long-term contracts most of which are linked to international oil and/or oil equivalent prices. The development of crude oil and natural gas discoveries in offshore areas and the development of shale gas plays are particularly dependent on the outlook for liquids and natural gas prices because of the large amount of capital expenditure required for development prior to commencing production.
A substantial and extended decline in the prices of crude oil, natural gas liquids and/or natural gas have resulted in delay or cancellation of drilling, development or construction programs, and curtailment in production and/or unutilized long-term transportation commitments, all of which could have a material adverse impact on the Company. Poor economics for developing assets have resulted in a reduction of drilling activity which may lead to loss of leases and skilled employees. The amount of cost oil required to recover the Company’s investment and costs in various PSCs is dependent on commodity prices, with higher commodity prices resulting in the booking of lower oil and gas reserves net of royalties. Moreover, changes in commodity prices may result in the Company making downward adjustments to the Company’s estimated reserves. If this occurs, or if the Company’s estimates of production or economic factors change, accounting rules may require the Company to impair, as a non-cash charge to earnings, the carrying value of the Company’s oil and gas properties. The Company is required to perform impairment tests on oil and gas properties whenever events or changes in circumstances indicate that the carrying value of properties may not be
16
recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company’s oil and gas properties, the carrying value may not be recoverable and, therefore, an impairment charge will be required to reduce the carrying value of the properties to their estimated fair value. The Company may incur impairment charges in the future, which could materially affect the Company’s results of operations, and its balance sheet, in the period incurred.
Credit and Liquidity
The Company’s financial performance and cash flow is highly sensitive to the prevailing prices of crude oil, natural gas liquids and natural gas, which fluctuate in response to a variety of factors beyond the Company’s control. A substantial and extended decline in the prices of crude oil, natural gas liquids or natural gas could negatively impact the Company’s liquidity and/or credit ratings and adversely affect the Company’s ability to comply with covenants under denominated long-term notes and credit facilities. See also “Risk Factors — Volatility of Crude Oil, Natural Gas Liquids and Natural Gas Prices.”
The volatility of credit markets can result in market conditions that may restrict timely access and limit the Company’s ability to secure and maintain cost-effective financing on acceptable terms and conditions. In addition, if any lender under the Company’s syndicated bank credit facility does not fund its commitment, the Company’s liquidity may be reduced by an amount up to the aggregate amount of such lender’s commitment. See also “Risk Factors — Counterparty Credit Risk.”
The credit rating agencies regularly evaluate the Company, and their ratings of the Company’s securities are based on a number of factors not entirely within the Company’s control, including the credit rating of the Company’s parent, Repsol, conditions affecting the oil and gas industry generally, and the wider state of the economy. There can be no assurance that one or more of the Company’s credit ratings will not be downgraded. A reduction in any of the Company’s current investment-grade credit ratings to below investment grade could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. In addition, the Company relies on access to letters of credit in the normal course of business in order to support some of its operations. For example, with respect to the Company’s North Sea operations, the Company relies on access to letters of credit facilities which entitle a bank to demand cash at any time to cover the full amount of any letter of credit issued with respect to UK decommissioning obligations. There can be no assurance that the Company will be able to obtain the necessary letters of credit or repay the full amount of a letter of credit upon demand. See also “Risk Factors — Capital Allocation and Project Decisions.”
Capital Allocation and Project Decisions
The Company’s long-term financial performance is sensitive to the capital allocation decisions taken and the underlying performance of the projects undertaken. Capital allocation and project decisions are undertaken after assessing reserve and production projections, capital and operating cost estimates and applicable fiscal regimes that govern the respective government take from any project. All of these factors are evaluated against common commodity pricing assumptions and the relative risks of projects. These factors are used to establish a relative ranking of projects and capital allocation, which is then calibrated to ensure the debt and liquidity of the Company is not compromised. However, material changes to project outcomes and deviation from forecasted assumptions, such as production volumes and rates, realized commodity price, cost or tax and/or royalties, could have a material impact on the Company’s cash flow and financial performance as well as assessed impacts of impairments on the Company’s assets. Adverse economic and/or fiscal conditions could impact the prioritization of projects and capital allocation to these projects, which in turn could lead to adverse effects such as asset under investment, asset performance impairments or land access expiries.
Uncertainties around some of the Company’s projects, including, but not limited to, its equity interest in TSEUK and the projects TSEUK undertakes, could result in changes to the Company’s capital allocation or its spend target being exceeded. The Company cannot be certain that funding, if needed, will be available to the extent required or on acceptable terms. To the extent that asset sales are necessary to fund capital requirements, the Company’s ability to sell assets is subject to market interest. If the Company is unable to access funding when needed on acceptable terms, the Company may not be able to fully implement its business plans, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the Company’s business, financial condition, cash flows, and results of operations. See also “Risk Factors — Credit and Liquidity” and “Risk Factors — Interest Rates.”
Counterparty Credit Risk
In the normal course of business, the Company enters into contractual relationships with counterparties in the energy industry and other industries, including suppliers and co-venturers and counterparties to commodity sale/purchase agreements. If such counterparties do not fulfil their contractual obligations or settle their liabilities to the Company, the Company may suffer losses, may have to proceed on a sole risk basis, may have to forgo opportunities or may have to relinquish leases or blocks. Fluctuations in prevailing prices of crude oil, natural gas liquids and natural gas could have a material adverse effect on the operations and financial condition of such counterparties. The Company also has credit risk arising from cash and cash
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equivalents held with banks and financial institutions. While the Company maintains a risk management system that limits exposures to any one counterparty, losses due to the failure by counterparties to fulfil their contractual obligations may adversely affect the Company’s financial condition.
Project Delivery
The Company manages a variety of projects, including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may impact expected revenues and project cost overruns could make projects uneconomic. The Company’s ability to complete projects depends upon numerous factors, many of which are beyond the Company’s control. These factors include the level of direct control by the Company, since many of the projects in which the Company is involved are not operated by the Company, and timing and project management control are the responsibility of the operator. See also “Risk Factors — Non-Operatorship and Partner Relations.” The global demand for project resources can impact the access to appropriately competent contractors and construction yards as well as to raw products, such as steel. Typical execution risks include the availability of seismic data, the availability of processing capacity, the availability and proximity of pipeline capacity, the availability of drilling and other equipment, the ability to access lands, weather, unexpected cost increases, accidents, the availability of skilled labour, including engineering and project planning personnel, the need for government approvals and permits, and regulatory matters. Subsurface challenges can also result in additional risk of cost overruns and scheduling delays if conditions are not typical of historical experiences. The Company utilizes materials and services which are subject to general industry-wide conditions. Cost escalation for materials and services may be unrelated to commodity price changes and may continue to have a significant impact on project planning and economics. The Company operates in challenging, environmentally hostile climates, such as Papua New Guinea, where logistical costs can be materially impacted by seasonal and occasionally unanticipated weather patterns. Contracts where work has been placed under a lump sum arrangement are subject to additional challenges related to scheduling, reputation and relationship management with the Company’s coventurers.
Ability to Find, Develop or Acquire Additional Reserves
The Company’s future success depends largely on its ability to find and develop, or acquire, additional oil and gas reserves that are economically recoverable. Hydrocarbons are a limited resource, and the Company is subject to increasing competition from other companies, including national oil companies. Exploration and development drilling may not result in commercially productive reserves and, if production begins, reservoir performance may be less than projected. Successful acquisitions require an assessment of a number of factors, many of which are uncertain. These factors include recoverable reserves, development potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. If a high impact prospect identified by the Company fails to materialize in a given year, the Company’s multi-year exploration and/or development portfolio may be compromised. See also “Risk Factors — Volatility of Crude Oil, Natural Gas Liquids and Natural Gas Prices”. The recent decline in commodity prices, if sustained, may result in promising exploration and development projects being deemed uneconomic. Continued failure to achieve anticipated reserve and resource addition targets may result in the Company’s withdrawal from an area, which in turn may result in a write-down of any associated reserves and/or resources for that area.
Uncertainty of Reserves Estimates
The process of estimating oil and gas reserves is complex and involves a significant number of assumptions in evaluating available geological, geophysical, engineering and economic data. In addition, the process requires future projections of reservoir performance and economic conditions; therefore, reserves estimates are inherently uncertain. Since all reserves estimates are, to some degree, uncertain, reserves classification attempts to qualify the degree of uncertainty involved.
Since the evaluation of reserves involves the evaluator’s interpretation of available data and projections of price and other economic factors, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on estimated uncertainty, and the estimates of future net revenue or future net cash flows prepared by different evaluators or by the same evaluators at different times may vary substantially.
Each year, the Company prepares evaluations of all of its reserves internally. Initial estimates of reserves are often based upon volumetric calculations and analogy to similar types of reservoirs, rather than actual well data and performance history. Estimates based on these methods generally are less certain than those based on actual performance. The Company may adjust its estimates and classification of reserves and future net revenues or cash flows based on results of exploration and development drilling and testing, additional performance history, prevailing oil and gas prices, and other factors, many of which are beyond the Company’s control. As new information becomes available, subsequent evaluations of the same reserves may continue to have variations in the estimated reserves, some of which may be material. In addition, the
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Company’s actual production, taxes, and development and operating expenditures with respect to its reserves will likely vary from such estimates and such variances could be material.
Operational Risks
Major Incident, Major Spill / Loss of Well Control
Oil and gas drilling and producing operations are subject to many risks, including the risk of fire, explosions, mechanical failure, pipe or well cement failure, well casing collapse, pressure or irregularities in formations, chemical and other spills, unauthorized access to hydrocarbons, illegal tapping of pipelines, accidental flows of oil, natural gas or well fluids, sour gas releases, contamination, vessel collision, structural failure, loss of buoyancy, storms or other adverse weather conditions and other occurrences. If any of these should occur, the Company could incur legal defence costs and remedial costs and could suffer substantial losses due to injury or loss of life, human health risks, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, unplanned production outage, cleanup responsibilities, regulatory investigation and penalties, increased public interest in the Company’s operational performance and suspension of operations. The Company’s horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
The Company maintains insurance that contemplates both first and third party exposures for the Company’s onshore and offshore operations globally. There is no assurance that this insurance will be adequate to cover all losses or exposures to liability. The Company believes that its coverage is aligned with customary industry practices and in amounts and at costs that the Company believes to be prudent and commercially practicable. While the Company believes these policies are customary in the industry, they do not provide complete coverage against all operating risks. In addition, the Company’s insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on the Company’s financial position, results of operations and cash flows. The insurance coverage that the Company maintains may not be sufficient to cover every claim made against the Company in the future. In addition, a major incident could impact the Company in such a way that it could lead to a prolonged shutdown of an asset which may have a material adverse effect on the Company’s business and affect the Company’s reputation as a competent operator.
The Company operates and drills wells in both mature producing areas such as the UK and North America and in several remote areas in multiple countries. In 2015, the Company also carried out drilling and seismic operations in the emerging areas of Papua New Guinea and Colombia. The Company may seek new leases and/or drill in similar environments in the future.
Health Hazards and Personal Safety Incidents
The employee and contractor personnel involved in exploration and production activities and operations of the Company are subject to many inherent health and safety risks and hazards, which could result in occupational illness or health issues, personal injury, and loss of life, facility quarantine and/or facility and personnel evacuation. For example, employees and contractors are subject to the possibility of loss of containment. This could lead to exposure to the release of high pressure materials as well as collateral shrapnel from piping or vessels which could result in personal injury and loss of life.
Security Incidents
The Company’s operations may be adversely affected by security-related incidents which are not within the control of the Company, such as war (external and internal conflicts) and remnants of war, sectarian violence, civil unrest, criminal acts, terrorism and abductions in locations where the Company operates. Security-related incidents may include allegations of human rights abuse associated with the provision of security to the Company operations. In particular, the Company faces increased security risks in the Kurdistan Region of Iraq, Colombia, Papua New Guinea and Algeria within the Company’s current portfolio. A significant security incident could result in the deferral of or termination of Company activity within the impacted areas of operations, thus adversely impacting execution of the Company’s business strategy (e.g., delaying exploration and development, causing a halt to production or forcing exit strategy processes), which could adversely affect the Company’s financial condition.
Regulatory Approvals/Compliance and Changes to Laws and Regulations
The Company’s exploration and production operations are subject to extensive regulation at many levels of government, including municipal, state, provincial and federal governments, in the countries where the Company operates, and operations are subject to interruption or termination by governmental and regulatory authorities based on environmental or other considerations. Moreover, the Company has incurred and will continue to incur costs in the Company’s efforts to comply
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with the requirements of environmental, safety and other regulations, such as the recently introduced Canadian Extractive Sector Transparency Measure Act and the recently re-proposed rules to implement Section 1504 of the U.S. Dodd-Frank Act, when enacted. Further, the regulatory environment in the oil and gas industry could change in ways that the Company cannot predict and that might substantially increase the Company’s costs of compliance and, in turn, materially and adversely affect the Company’s business, results of operations and financial condition.
Failure to comply with the applicable laws or regulations may result in significant increases in costs, fines or penalties and even shutdowns or losses of operating licences or criminal sanctions. If regulatory approvals or permits required for operations are delayed or not obtained, the Company could experience delays or abandonment of projects, decreases in production and increases in costs. This could result in an inability of the Company to fully execute its strategy and adverse impacts on its financial condition. See also “Risk Factors — Fiscal Stability” and “Risk Factors — Socio-Political Risks.”
Changes to existing laws and regulations or new laws could have an adverse effect on the Company’s business by increasing costs, impacting development schedules, reducing revenue and cash flow from natural gas and oil sales, reducing liquidity or otherwise altering the way the Company conducts business. There have been various proposals to enact new, or amend existing, laws and regulations relating to greenhouse gas emissions, hydraulic fracturing (including associated additives, water use, induced seismicity, and disposal) and shale gas development generally. For example, in Colombia, the high level of oil and gas activity in the country has resulted in significant delays in the granting of the required environmental licences. These delays may result in reduced near-term production. See also “Risk Factors — Environmental Risks.”
The Company continues to monitor and assess any new policies, legislation, regulations and treaties in the areas where the Company operates to determine the impact on the Company’s operations. Governmental organizations unilaterally control the timing, scope and effect of any currently proposed or future laws, regulations or treaties, and such enactments are subject to a myriad of factors, including political, monetary and social pressures. The Company acknowledges that the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect the Company’s business, results of operations and financial condition.
Fiscal Stability
Governments may amend or create new legislation that could impact the Company’s operations and that could result in increased capital, operating and compliance costs. Moreover, the Company’s operations are subject to various levels of taxation in the countries where the Company operates. Federal, provincial, and state income tax rates or incentive programs relating to the oil and gas industry in the jurisdictions where the Company operates may in the future be changed or interpreted in a manner that could materially affect the economic value of the respective assets. For example, the US Congress has been considering a revision of the immediate deduction currently available for drilling costs. The Government of Alberta has recently announced the results of a royalty review. While many details of the implementation of this new regime have yet to be determined, royalties on existing wells remain unchanged for 10 years, and the new royalties will apply only to wells drilled in 2017 and onwards. Furthermore, the Government has pledged that the new system will be, in aggregate, “rate of return neutral” relative to the existing system, although individual assets may see higher or lower royalties. The impact of the new royalty regime to the Company has not yet been fully evaluated.
Stakeholder Opposition
The Company’s planned activities may be adversely affected if there is strong community opposition to its operations. For example, local community concerns in parts of Colombia, the Kurdistan Region of Iraq and Papua New Guinea could potentially result in development and production delays in those operations. There is also heightened public concern regarding hydraulic fracturing in parts of North America, which could materially affect the Company’s shale operations. In some circumstances, this risk of community opposition may be higher in areas where the Company operates alongside indigenous communities who may have additional concerns regarding land ownership, usage or claim compensation.
Socio-Political Risks
The Company’s operations may be adversely affected by political or economic developments or social instability in the jurisdictions in which it operates, which are not within the control of the Company, including, among other things, a change in crude oil, natural gas liquids or natural gas pricing policy and/or related regulatory delays, the risks of war, terrorism, abduction, expropriation, nationalization, renegotiation or nullification of existing concessions and contracts, difficulties in enforcing contractual terms, a change in taxation policies, economic sanctions, the imposition of specific drilling obligations, the imposition of rules relating to development and abandonment of fields, access to or development of infrastructure, jurisdictional boundary disputes, and currency controls. As a result of the continuing evolution of an international framework for corporate responsibility and accountability for international crimes, the Company could also be exposed to potential
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claims for alleged breaches of international law, health, safety and environmental regulations, and other human rights-based litigation risk. Numerous countries in which the Company has interests, including, but not limited to, the Kurdistan Region of Iraq, Colombia, Vietnam, Algeria and Indonesia, have been subject to recent economic or political instability, disputes and social unrest, and military or rebel hostilities. The potential deterioration of socio-political security situations (i.e. political instability and/or disputes) poses increased risk, which may result in the cessation of operations as well as the delay in payment or exports such as, in the Kurdistan Region of Iraq with respect to the regularity and predictability of export payment arrangements during a state of conflict, and in Vietnam and Malaysia with respect to China’s claim over disputed waters in the East Sea. In addition, the Company regularly evaluates opportunities worldwide, and may in the future engage in projects or acquire properties in other nations that are experiencing economic or political instability, social unrest, military hostilities or United Nations, US or other international sanctions. Some of the foregoing government actions may lead to political or reputational pressures on the Company from non-governmental organizations, home governments and security holders.
Non-Operatorship and Partner Relations
Some of the Company’s projects are conducted in joint venture environments where the Company has a limited ability to influence or control operations or future development, safety and environmental standards, and amount of capital expenditures. Companies which operate these properties may not necessarily share the Company’s health, safety and environmental standards or strategic or operational goals or approach to partner relationships, which may result in accidents, regulatory noncompliance, project delays or unexpected future costs, all of which may affect the viability of these projects and the Company’s standing in the external market.
The Company is also dependent on other working interest co-participants of these projects to fund their contractual share of the capital expenditures. If these co-participants are unable to fund their contractual share of, or do not approve, the capital expenditures, the co-participants may seek to defer programs, resulting in strategic misalignments and a delay of a portion of development of the Company’s programs, or the co-participants may default, such that projects may be delayed and/or the Company may be partially or totally liable for their share.
Some of the Company’s projects involve transition of operatorship as part of a joint venture, which requires a significant amount of effort and coordination.
Litigation
From time to time, the Company is the subject of litigation arising out of the Company’s operations. Specific disclosure of current legal proceedings, and the risks associated with current proceedings and litigation generally, are disclosed under the heading “Legal Proceedings.”
Exchange Rate Fluctuations
Results of operations are affected primarily by the exchange rates between the US$, the C$ and UK£. These exchange rates may vary substantially. Most of the Company’s revenue is received in or is referenced to US$ denominated prices (including the Company’s Consolidated Financial Statements, which are presented in US$), while the majority of the Company’s expenditures are denominated in US$, C$ and UK£. A change in the relative value of the US$ against the C$ or the UK£ would also result in an increase or decrease in the Company’s UK£ denominated debt, as expressed in US$, and the related interest expense. The Company is also exposed to fluctuations in other foreign currencies.
Environmental Risks
General
All phases of the Company’s oil and natural gas business are subject to environmental regulation pursuant to a variety of laws and regulations in the countries where the Company does business. These laws and regulations may require the acquisition of a permit before operations commence, restrict the types, quantities and concentration of substances that can be released into the environment in connection with the Company’s drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution that may result from the Company’s operations. The Company’s business is subject to the trend toward increased rigour in regulatory compliance and civil or criminal liability for environmental matters in certain regions (e.g., Canada, the United States and the European Union). Compliance with environmental legislation can require significant expenditures, and failure to comply with environmental legislation may result in the assessment of administrative, civil and criminal penalties, the cancellation or suspension of regulatory permits, the imposition of investigatory or remedial obligations or the issuance of injunctions restricting or prohibiting certain activities. Under existing environmental laws and regulations, the Company
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could be held strictly liable for the remediation of previously released materials or property contamination resulting from its operations, regardless of whether those operations were in compliance with all applicable laws at the time they were performed. Regulatory delays, legal proceedings and reputational impacts from an environmental incident could result in a material adverse effect on the Company’s business. Increased stakeholder concerns and regulatory actions regarding shale gas development could lead to third party or governmental claims, and could adversely affect the Company’s business and financial condition. Although the Company currently believes that the costs of complying with environmental legislation and dealing with environmental civil liabilities will not have a material adverse effect on the Company’s financial condition or results of operations, there can be no assurance that such costs will not have such an effect in the future.
Hydraulic Fracturing
The Company utilizes horizontal drilling, multi-stage hydraulic fracturing, specially formulated drilling fluids and other technologies in its drilling and completion activities. Hydraulic fracturing is a method of increasing well production by injecting fluid under high pressure down a well, which causes the surrounding rock to crack or fracture. The fluid typically consists of water, sand, chemicals and other additives and flows into the cracks where the sand remains to keep the cracks open and enable natural gas or liquids to be recovered. Fracturing fluids flow back to the surface through the wellbore and are stored for reuse or future disposal in accordance with regional regulations, which may include injection into underground wells. The design of the well bores protects groundwater aquifers from the fracturing process.
Hydraulic fracturing has been in use for some time in the oil and gas industry, however, the proliferation of fracturing in recent years to access hydrocarbons in unconventional reservoirs, such as shale formations, has given rise to public concerns about the environmental impacts of this technology. Public concern over the environmental impacts of the hydraulic fracturing process has focused on a number of issues, including water aquifer contamination; other qualitative and quantitative effects on water resources as large quantities of water are used and injected fluids either remain underground or flow back to the surface to be collected, treated and disposed; and the potential for fracturing activities to induce seismic events. Regulatory authorities in certain jurisdictions have announced initiatives in response to such concerns. Federal, provincial, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect the Company’s production. Public perception of environmental risks associated with hydraulic fracturing can further increase pressure to adopt new laws, regulation or permitting requirements, or lead to regulatory delays, legal proceedings and/or reputational impacts. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delay, increased operating costs, and third party or governmental claims. They could also increase the Company’s costs of compliance and doing business as well as delay the development of hydrocarbon (natural gas and oil) resources from shale formations, which may not be commercial without the use of hydraulic fracturing.
Due to the adoption of legal restrictions in New York, or if legal restrictions are adopted in other areas where the Company is currently conducting or in the future plans to conduct operations, the Company may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. In addition, if hydraulic fracturing becomes more regulated, the Company’s fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves. It is anticipated that federal, provincial and state regulatory frameworks to address concerns related to hydraulic fracturing will continue to emerge. While we are unable to predict the impact of any potential regulations upon our business, the implementation of new regulations with respect to water usage or hydraulic fracturing generally could increase the Company’s costs of compliance, operating costs, the risk of litigation and environmental liability, or negatively impact the Company’s prospects, any of which may have a material adverse effect on our business, financial condition and results of operations.
Seismicity
Seismicity events have been recorded as occurring at the same time that the Company has been conducting hydraulic fracturing and related operations. Although the size of these events is considered light, they raise stakeholder and regulatory concerns. Due to recent seismic activity reported in the Fox Creek area of Alberta, the Alberta Energy Regulator (“AER”) has announced new seismic monitoring and reporting requirements for hydraulic fracturing operators in the Duvernay zone in the Fox Creek area. These requirements include, among others, an assessment of the potential for seismicity prior to operations, real time monitoring of seismic activity, the implementation of a response plan to address potential events, and the suspension of operations when a seismic event above a particular threshold occurs. The AER continues to monitor seismic activity around the province and may extend these requirements to other areas of the province, or introduce more stringent measures, if deemed appropriate. This could impact the Company’s future development plans as operations may be under
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more regulatory scrutiny. The foregoing or any future AER requirements could lead to additional costs, delays or curtailment of exploration, development, or production activities, and perhaps preclude the use of hydraulic fracturing programs in the area. In addition, if monitoring seismicity becomes more regulated, the Company’s fracturing activities could become subject to additional permitting requirements and result in delays as well as potential increases in costs. Restrictions on hydraulic fracturing due to a perceived correlation to seismicity could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves in the affected areas.
Greenhouse Gas Emissions
The Company is subject to various greenhouse gas (“GHG”) emissions-related legislation. Current GHG emissions legislation does not result in material compliance costs, but compliance costs may increase in the future and may impact the Company’s operations and financial results. The Company operates in jurisdictions with existing GHG legislation (e.g., UK, United States and Canada, notably Alberta and British Columbia) as well as in regions which currently do not have GHG emissions legislation and jurisdictions where GHG emissions legislation is emerging or is subject to change. The Company monitors GHG legislative developments in all areas in which the Company operates. Potential new or additional GHG legislation and associated compliance costs, in particular in association with the adoption of the Paris Agreement under the United Nations Framework Convention on Climate Change, may have a material impact on the Company.
Environmental and Decommissioning Liabilities
The Company is involved in the operation and maintenance of facilities and infrastructure in difficult and challenging areas, including offshore, deepwater, jungle and desert environments. Despite the Company’s implementation of health, safety and environmental standards, there is a risk that accidents or regulatory non-compliance can occur, the outcomes of which, including remedial work or regulatory intervention, cannot be foreseen or planned for. The Company expects to incur site restoration costs over a prolonged period as existing fields are depleted. The Company provides for decommissioning liabilities in its annual Consolidated Financial Statements in accordance with IFRS. Additional information regarding decommissioning liabilities is set forth in the notes to the annual Consolidated Financial Statements. The process of estimating decommissioning liabilities is complex and involves significant uncertainties concerning the timing of the decommissioning activity; legislative changes; technological advancement; regulatory, environmental and political changes; and the appropriate discount rate used in estimating the liability. Any change to these assumptions could result in a change to the decommissioning liabilities to which the Company is subject. In the Company’s North Sea operations, changes in these assumptions would potentially have a significant impact on the Company’s decommissioning liabilities because of the assessed size of these future costs. Any changes to decommissioning estimates influence the value of letters of credit to be provided pursuant to the decommissioning security agreements. There can be no assurances that the cost estimates and decommissioning liabilities are materially correct and that the liabilities will occur when predicted. In addition, with respect to some operations, the Company is not the operator and may not determine the cost estimates or timing of decommissioning such that cost overruns are possible, the Company is often jointly and severally liable for the decommissioning costs associated with the Company’s various operations and could, therefore, be required to pay more than its net share.
Attraction, Retention and Development of Personnel
Successful execution of the Company’s plans is dependent on the Company’s ability to attract and retain talented personnel who have the skills necessary to deliver on the Company’s strategy and maintain safe operations. This includes not only key talent at a senior level, but also individuals with the professional and technical skill sets critical for the Company’s business, particularly geologists, geophysicists, engineers, accountants and other specialists.
Information Systems
Many of the Company’s business processes depend on the availability, capacity, reliability and security of the Company’s information technology (“IT”) infrastructure and the Company’s ability to expand and continually update this infrastructure in response to the Company’s changing needs. The Company’s IT systems are increasingly integrated in terms of geography, number of systems, and key resources supporting the delivery of IT systems. Further, as a result of the completion of the Repsol Transaction, the Company’s IT systems require integration with, or possibly replacement by, Repsol IT systems. The performance of the Company’s key suppliers is critical to ensure appropriate delivery of key services. Any failure to manage, expand and update the Company’s IT infrastructure, any failure in the extension or operation of this infrastructure, or any failure by the Company’s key resources or service providers in the performance of their services could materially and adversely harm the Company’s business.
The ability of the IT function to support the Company’s business in the event of a disaster such as fire, flood or loss/denial of any of the Company’s data centres or major office locations and the Company’s ability to recover key systems from
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unexpected interruptions cannot be fully tested. There is a risk that, if such an event actually occurs, the business continuity plan may not be adequate to immediately address all repercussions of the disaster. In the event of a disaster affecting a data centre or key office location, key systems may be unavailable for a number of days, leading to inability to perform some business processes in a timely manner.
In addition, the increasing risk of information security breaches, including more sophisticated attempts often referred to as advanced persistent threats, requires the Company to continually improve its ability to detect and prevent such occurrences. Disruption of critical IT services, or breaches of information security, could have a negative effect on the Company’s operational performance and earnings, as well as on the Company’s reputation.
Egress and Gas & Liquids Buyers
As increasing volumes of natural gas and liquids are brought on-stream by the Company and others, transportation and processing infrastructure capacity may, at times, be exceeded before capacity additions become available. In such an event, there is a risk that the transportation and/or processing of some of the Company’s production may be restricted or delayed until pipeline connection or infrastructure additions are complete. In Canada and in the Eagle Ford area in the US, the Company has secured sufficient access to infrastructure for both liquids and gas for the near and medium term, and it is expected that any restrictions on production due to lack of infrastructure capacity would be relatively short-term (more operational in nature) and would not impact a material quantity of production. Ensuring that the Company holds sufficient transportation capacity to take gas supplies from the Marcellus area, which has seen a significant growth in industry production over the past few years, to market is critical to ensuring the ability to flow production on an unrestricted basis as well as to maximize the value for the Company’s production. Another associated risk will be the availability and diversity of contract and credit-enabled buyers. Should the Company be unable to secure access to infrastructure and qualified buyers for its production, the Company could face reduced production and/or materially lower prices on some portion of production, which in turn could adversely affect the Company’s operating results.
Interest Rates
The Company is exposed to interest rate risk principally by virtue of its borrowings. Borrowing at floating rates exposes the Company to short-term movements in interest rates. Borrowing at fixed rates exposes the Company to reset risk associated with debt maturity. Most of the Company’s debt is issued at fixed interest rates; therefore, the Company’s main exposure to changes in interest rates would occur in respect of short-term investments or borrowings in the event that substantial cash balances are invested in or owed to the Company.
Competitive Risk
The global oil and gas industry is highly competitive. The Company faces significant competition and many of the Company’s competitors have resources in excess of the Company’s available resources. The Company actively competes for the acquisition and divestment of properties, the exploration for and development of new sources of supply, the contractual services for oil and gas drilling and production equipment and services, the transportation and marketing of current production, and industry personnel, including, but not limited to, geologists, geophysicists, engineers and other specialists that enable the business. Many of the Company’s competitors have the ability to pay more for seismic and lease rights in crude oil and natural gas properties and exploratory prospects. They can define, evaluate, bid for and purchase a greater number of properties and prospects than the Company’s financial or human resources permit. If the Company is not successful in the competition for oil and gas reserves or in the marketing of production, the Company’s financial condition and results of operations may be adversely affected. Many of the Company’s competitors have resources substantially greater than the Company’s and, as a consequence, the Company may be at a competitive disadvantage.
Corruption & Fraud
The Company’s operations are governed by the laws of many jurisdictions, which generally prohibit bribery and other forms of corruption. The Company requires all employees to participate in ethics awareness training, which includes the Company’s policies against giving or accepting money or gifts in certain circumstances. Despite the training and policies, it is possible that the Company, or some of its employees or contractors, could be charged with bribery or corruption. If the Company is found guilty of such a violation, which could include a failure to take effective steps to prevent or address corruption by its employees or contractors, the Company could be subject to onerous penalties. Depending on its nature and scope, a mere investigation itself could lead to significant corporate disruption, high legal costs and forced settlements (such as the imposition of an internal monitor). In addition, bribery allegations or bribery or corruption convictions could impair the Company’s ability to work with governments or non-governmental organizations. Such convictions or allegations could result in the formal exclusion of the Company from a country or area, national or international lawsuits, government
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sanctions or fines, project suspension or delays, reduced market capitalization, reputational impacts and increased investor concern.
TRANSFER AGENTS AND REGISTRARS
Computershare Trust Company of Canada, at 600, 530 — 8th Avenue SW, Calgary, Alberta, T2P 3S8, along with its US co-transfer agent, Computershare Trust Company N.A., acts as trustee for various public debt securities. JPMorgan Chase Bank N.A., London Branch (now The Bank of New York Mellon, pursuant to bulk novation orders granted on April 3, 2007 and July 1, 2008), One Canada Square, London, UK, E14 5AL, acts as trustee for the 6.625% unsecured notes listed on the London Stock Exchange. Union Bank N.A., 120 S. San Pedro Street, Suite 400, Los Angeles, California, 90012, acts as trustee for various public debt securities. The Company has not retained transfer agents for any other outstanding securities.
INTERESTS OF EXPERTS
The Company’s auditors are Ernst & Young LLP, Chartered Professional Accountants, Ernst & Young Tower, 1000, 440 - 2nd Avenue SW, Calgary, Alberta, T2P 5E9. Ernst & Young LLP is independent in accordance with the Chartered Professional Accountants of Alberta Rules of Professional Conduct.
Mr. Mark Ireland, an employee of the Company, has provided the report on reserves data, included in Schedule “A” to this Annual Information Form, in his capacity as the Company’s Internal Qualified Reserves Evaluator.
ADVISORIES
Forward-Looking Information
This Annual Information Form contains or incorporates by reference information that constitutes “forward-looking information” or “forward-looking statements” (collectively “forward-looking information”) within the meaning of applicable securities legislation. Forward-looking information is included throughout this Annual Information Form, including among other places, under the headings “General Development of the Business,” “Description of the Business,” “Corporate Responsibility and Environmental Protection,” “Legal Proceedings” and “Risk Factors.” This forward-looking information includes, but is not limited to, statements regarding:
· business strategy, priorities and plans;
· expected capital expenditures, timing and planned focus of such spending;
· expected capital sources to fund the Company’s capital program;
· expected production and timing of such production;
· planned drilling, development and seismic acquisition;
· expected results from the Company’s portfolio of oil and gas assets;
· expected abandonment and reclamation costs;
· anticipated funding of decommissioning liabilities;
· anticipated timing and results of legal proceedings;
· anticipated closing and timing of closing of planned dispositions; and
· other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance.
Statements concerning oil and gas reserves contained in this Annual Information Form in Schedule A and elsewhere may be deemed to be forward-looking information as they involve the implied assessment that the resources described can be profitably produced in the future.
The factors or assumptions on which the forward-looking information is based include: commodity price and cost assumptions; projected capital investment levels; the flexibility of capital spending plans and the associated sources of funding; the successful and timely implementation of capital projects; the continuation of tax, royalty and regulatory regimes; the ability to obtain regulatory and partner approval; and other risks and uncertainties described in the filings made by the Company with securities regulatory authorities. The Company believes the material factors, expectations and assumptions
25
reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. Forward-looking information for periods past 2016 assumes escalating commodity prices.
Undue reliance should not be placed on forward-looking information. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks which could cause actual results to vary, and, in some instances, to differ materially from those anticipated by the Company and described in the forward-looking information contained in this Annual Information Form. The material risk factors include, but are not limited to:
· fluctuations in oil and gas prices, foreign currency exchange rates, interest rates and tax or royalty rates;
· the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas;
· risks and uncertainties involving geology of oil and gas deposits;
· risks associated with project management, project delays and/or cost overruns;
· uncertainty related to securing sufficient egress and access to markets;
· the uncertainty of reserves and resources estimates, reserves life and underlying reservoir risk;
· the uncertainty of estimates and projections relating to production, costs and expenses, including decommissioning liabilities;
· risks related to strategic and capital allocation decisions, including potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
· health, safety, security and environmental risks, including risks related to the possibility of major accidents;
· environmental regulatory and compliance risks, including with respect to greenhouse gases and hydraulic fracturing;
· uncertainties as to access to capital, including the availability and cost of credit and other financing, and changes in capital markets;
· risks in conducting foreign operations (for example, civil, political and fiscal instability and corruption);
· risks related to the attraction, retention and development of personnel;
· changes in general economic and business conditions;
· the possibility that government policies, regulations or laws may change or governmental approvals may be delayed or withheld; and
· results of the Company’s risk mitigation strategies, including insurance activities.
The foregoing list of risk factors is not exhaustive. Additional information on these and other factors which could affect the Company’s operations or financial results or strategy are included under the heading “Risk Factors” and elsewhere in this Annual Information Form. In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the SEC.
Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is presented. The Company assumes no obligation to update forward-looking information should circumstances or management’s estimates or opinions change, except as required by law.
Oil and Gas Information
All references to reserves volumes in this Annual Information Form are to reserves volumes estimated in accordance with Canadian disclosure standards.
The Company makes reference to production volumes throughout this Annual Information Form. Where not otherwise indicated, such production volumes are stated on a gross basis, which means they are stated prior to the deduction of royalties and similar payments.
Natural gas is converted to a barrel of oil equivalent (boe) at the ratio of 5.615 thousand cubic feet (mcf) to one barrel (bbl) of oil. Oil is converted to natural gas equivalent (mcfe) at the ratio of one bbl to 5.615 mcf of natural gas. The boe and mcfe measures may be misleading, particularly if used in isolation. A boe conversion ratio of 5.615 mcf to 1 bbl and an mcfe
26
conversion ratio of 1 bbl to 5.615 mcf are based on an energy equivalence conversion method primarily applicable at the burner tip and do not represent a value equivalence at the wellhead.
EXCHANGE RATE INFORMATION
Except where otherwise indicated, all dollar amounts in this Annual Information Form are stated in US dollars (“US$” or “$”). The following table sets forth the Canada/US exchange rates on the last trading day of the years indicated as well as the high, low and average rates for such years. The high, low and average exchange rates for each year were identified or calculated from spot rates in effect on each trading day during the relevant year. The exchange rates shown are expressed as the number of Canadian dollars (“C$”) required to purchase one US$. These exchange rates are based on those published on the Bank of Canada’s website as being in effect at approximately noon on each trading day (the “Bank of Canada noon rate”).
| | Year ended December 31 | |
| | 2015 | | 2014 | | 2013 | |
Year-end | | 1.3903 | | 1.1601 | | 1.0636 | |
High | | 1.1728 | | 1.0614 | | 0.9839 | |
Low | | 1.3990 | | 1.1643 | | 1.0697 | |
Average | | 1.2787 | | 1.1045 | | 1.0299 | |
27
ABBREVIATIONS
The abbreviations used in this Annual Information Form have the following meanings:
bbl | | barrel |
bbls | | barrels |
bbls/d | | barrels per day |
bcf | | billion cubic feet |
bcfe | | billion cubic feet equivalent |
boe | | barrels of oil equivalent |
bopd | | barrels of oil per day |
boe/d | | barrels of oil equivalent per day |
mbbls | | thousand barrels |
mboe/d | | thousand barrels oil equivalent per day |
mcf | | thousand cubic feet |
mcfe | | thousand cubic feet equivalent |
mmbbls | | million barrels |
mmbbls/d | | million barrels per day |
mmboe | | million barrels of oil equivalent |
mmcf/d | | million cubic feet per day |
mmcfe/d | | millions of cubic feet equivalent per day |
tcf | | trillion cubic feet |
C$ | | Canadian dollar |
COGEH | | Canadian Oil and Gas Evaluation Handbook |
HH | | Henry Hub |
IFRS | | International Financial Reporting Standards |
IQRE | | Internal Qualified Reserves Evaluator |
JOC | | Joint Operating Company |
km | | kilometre |
LNG | | Liquefied Natural Gas |
NGL | | Natural Gas Liquids |
UK | | United Kingdom |
UK£ | | Pound sterling |
US | | United States of America |
US$ or $ | | United States dollar |
WTI | | West Texas Intermediate |
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MATERIAL CONTRACTS
The only material contract the Company was subject to during the last completed financial year was the Arrangement Agreement, providing for the acquisition of the Company through a plan of arrangement pursuant to the Canada Business Corporations Act entered into on December 15, 2014. This transaction closed May 8, 2015.
ADDITIONAL INFORMATION
Additional information related to the Company, including the information incorporated by reference herein, may be found on SEDAR at www.sedar.com and on Edgar at www.sec.gov.
Additional financial information is provided in the Company’s audited Consolidated Financial Statements for the year ended December 31, 2015 and related annual Management’s Discussion and Analysis.
Copies of the Company’s annual documents may be obtained from the Company’s website at www.repsol.com/ca_en/ or upon request from: Communications and External Relations Department, Repsol Oil & Gas Canada Inc., 2000, 888 — 3rd Street SW, Calgary, Alberta, T2P 5C5, email: infocanada@repsol.com.
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SCHEDULE A — RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Table of Contents
INTRODUCTION | 31 |
INTERNAL EVALUATION | 31 |
RESERVES DATA AND OTHER OIL AND GAS INFORMATION | 32 |
REPORT ON RESERVES DATA BY THE COMPANY’S INTERNAL QUALIFIED RESERVES EVALUATOR | 64 |
REPORT OF MANAGEMENT AND DIRECTORS ON NI 51-101 RESERVES DATA AND OTHER INFORMATION | 65 |
30
INTRODUCTION
As a Canadian reporting issuer, the Company is subject to the disclosure requirements of National Instrument NI 51-101 (“NI 51-101”) of the Canadian Securities Administrators, which applies to the disclosure of reserves and other oil and gas information. The disclosure in this Schedule A has been prepared in compliance with the annual disclosure requirements of NI 51-101.
The Company’s investments in Equion and TSEUK are accounted for using the equity method of accounting. NI 51-101 currently requires that, in such circumstances, the Company’s share of the reserves and future net revenues of Equion and TSEUK be disclosed separately from the Company’s reserves and future net revenue. Accordingly, in a number of the tables which follow, information is first provided in respect of the Company and its subsidiaries which is consolidated for financial reporting purposes (under the heading “Consolidated Entities”) and then in respect of Equion and TSEUK (under the heading “Equity Investments”). All information in respect of Equion and TSEUK reflects the Company’s 49% equity interest in Equion and 51% equity interest in TSEUK. Unless otherwise indicated, all references in this Schedule to the Company’s reserves include the reserves attributable to its equity investments in Equion and TSEUK. The reserves for Equion and TSEUK were evaluated internally by the Company in the same manner as the consolidated reserves for the Company, as described below.
INTERNAL EVALUATION
The Company’s oil and gas reserves are evaluated internally. The Company has obtained an exemption from NI 51-101 that exempts the Company from the requirement under NI 51-101 to have its reserves evaluated or audited by independent reserves evaluators. The following discussion is provided pursuant to the requirements of the exemption.
The Company understands that the purpose of the requirement under NI 51-101 for the involvement of independent qualified evaluators or auditors is to ensure that disclosure of reserves information reflects the conclusions of qualified professionals applying consistent standards and that such conclusions are not affected by adverse influences. The Company believes that using independent evaluators or auditors would not materially enhance the reliability of its reserves estimates in light of the expertise of its internal reserves evaluation personnel and the controls applied during its reserves evaluation process. The Company believes that its internal resources are at least as extensive as, if not greater than, those which would be assigned by any independent evaluators or auditors engaged by the Company, and that its internal staff’s knowledge of and experience with the Company’s reserves enable the Company to prepare an evaluation at least equivalent to that of any independent evaluator or auditor.
As at December 31, 2015, the Company’s internal reserves evaluation staff included more than 83 persons with full-time or part-time responsibility relating to participation in the Company’s reserves process, of whom 24 were “qualified reserves evaluators” for purposes of NI 51-101. The qualified reserves evaluators have an average of approximately 8 years of relevant experience in evaluating reserves. The Company’s internal reserves evaluation management personnel are responsible for reserves evaluation management and are directly involved in evaluating reserves and/or overseeing the reserves evaluation process. The Company has appointed an Internal Qualified Reserves Evaluator (“IQRE”) who is responsible for the preparation and validation of the Company’s reserves evaluations and the submission to the Company’s Board of Directors of reports thereon and reports directly to the Chief Executive Officer in that role. The Company’s IQRE is Mark Ireland, a graduate of Pennsylvania State University with B.S. and M.S. degrees in Petroleum Engineering. Mr. Ireland has more than 30 years of petroleum engineering experience internationally and in North America. He is a professional engineer registered in both Texas and Alberta and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
The Company has adopted a corporate policy that prescribes procedures and standards to be followed in preparing its reserves data. The following summarizes the Company’s current process for preparing and approving its publicly disclosed reserves data.
All of the Company’s reserves are evaluated annually. The Company employs qualified, competent, experienced engineers and geoscientists to ensure consistently high levels of professionalism in the estimation of its reserves data. Technical, cost and economic assumptions underpinning reserves estimates are documented to provide a clear audit trail.
The Company conducts formal reviews during the reserves estimation process to ensure the reasonableness, completeness and accuracy of input data; the appropriateness of the technical subsurface methodology; the full understanding of reserves movements; and the correct use of reserves classifications. All reserves estimates are reviewed and approved by senior management responsible for the operating area to which the reserves relate and then submitted to the Chief Executive Officer
31
for review and approval. In addition, the IQRE conducts a separate review to ensure the effectiveness of the disclosure controls and that the reserves estimates are free from material misstatement. The reserves data and the reports of the IQRE thereon are then reviewed by the Board of Directors.
Notwithstanding that the Company is exempt from the independent evaluator requirements of NI 51-101, the Company obtains annual independent audits of its reserves estimates for some of its properties on a rotating basis. Over the past four years, these rotational independent audits have covered, in aggregate, properties which, at December 31, 2015, represent approximately 78% of the Company’s proved plus probable reserves (on a boe basis) as at December 31, 2015. At the time of the audits, these audits have not revealed any material discrepancies in the reserves reported at such time using the standards in effect at the time of the audit. The Company’s IQRE oversees the preparation of the independent audits. The Company maintains a Reserves and Resources Data Policy and Procedures Manual, which it updates as appropriate and on a periodic basis. The Company also conducts periodic internal audits of the procedures, records and controls relating to the preparation of reserves data. Accordingly, the Company considers the reliability of its internally generated reserves data to be not materially less than would be afforded by the independent evaluator requirements of NI 51-101.
RESERVES DATA AND OTHER OIL AND GAS INFORMATION
The effective date of the reserves data and other oil and gas information in this section is December 31, 2015 and the preparation date is February 26, 2016.
It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates on the Company’s properties provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
In accordance with NI 51-101, the estimates of reserves and future net revenue set forth below are based on forecast prices and costs.
Definitions of the various terms used in the following tables are set forth under “Definitions” below. In certain of the tables set forth below, the columns may not add due to rounding.
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Reserves Estimates (Forecast Prices and Costs)(1)
| | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | Natural Gas
Liquids (mmbbls) | |
Year ended December 31, 2015 | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 2.1 | | 1.8 | | 26.4 | | 23.2 | | — | | — | | 31.0 | | 28.9 | | 397.0 | | 379.4 | | 23.9 | | 19.0 | |
Proved Developed Non-Producing | | 0.1 | | 0.1 | | — | | — | | — | | — | | 0.1 | | 0.1 | | 4.6 | | 4.4 | | 0.1 | | 0.2 | |
Proved Undeveloped | | — | | — | | 0.4 | | 0.4 | | — | | — | | 12.3 | | 11.6 | | 39.4 | | 38.0 | | 3.7 | | 3.2 | |
Total Proved | | 2.2 | | 1.9 | | 26.8 | | 23.6 | | — | | — | | 43.4 | | 40.6 | | 441.0 | | 421.8 | | 27.7 | | 22.4 | |
Total Probable | | 0.8 | | 0.7 | | 7.4 | | 6.5 | | — | | — | | 27.3 | | 25.1 | | 161.9 | | 152.4 | | 12.9 | | 10.1 | |
Total Proved Plus Probable | | 3.0 | | 2.6 | | 34.2 | | 30.1 | | — | | — | | 70.7 | | 65.7 | | 602.9 | | 574.2 | | 40.6 | | 32.5 | |
United States | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | — | | — | | — | | — | | 4.4 | | 3.3 | | 1,222.6 | | 1,027.0 | | 16.1 | | 13.6 | | 21.4 | | 16.0 | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | 25.9 | | 21.8 | | — | | — | | — | | — | |
Proved Undeveloped | | — | | — | | — | | — | | 5.0 | | 3.8 | | 686.4 | | 572.7 | | — | | — | | 17.3 | | 12.9 | |
Total Proved | | — | | — | | — | | — | | 9.4 | | 7.1 | | 1,934.9 | | 1,621.5 | | 16.1 | | 13.6 | | 38.7 | | 28.9 | |
Total Probable | | — | | — | | — | | — | | 2.1 | | 1.6 | | 749.9 | | 633.0 | | 10.1 | | 8.6 | | 10.1 | | 7.5 | |
Total Proved Plus Probable | | — | | — | | — | | — | | 11.5 | | 8.7 | | 2,684.8 | | 2,254.5 | | 26.2 | | 22.2 | | 48.8 | | 36.4 | |
Southeast Asia(2) | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 15.6 | | 11.4 | | — | | — | | — | | — | | — | | — | | 851.4 | | 609.5 | | 8.0 | | 3.9 | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | 64.0 | | 44.7 | | 0.3 | | 0.2 | |
Proved Undeveloped | | — | | — | | — | | — | | — | | — | | — | | — | | 205.2 | | 144.4 | | 0.9 | | 0.4 | |
Total Proved | | 15.6 | | 11.4 | | — | | — | | — | | — | | — | | — | | 1,120.6 | | 798.6 | | 9.2 | | 4.5 | |
Total Probable | | 63.5 | | 47.9 | | — | | — | | — | | — | | — | | — | | 691.5 | | 528.8 | | 7.2 | | 3.7 | |
Total Proved Plus Probable | | 79.1 | | 59.3 | | — | | — | | — | | — | | — | | — | | 1,812.1 | | 1,327.4 | | 16.4 | | 8.2 | |
Latin America(3) | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | — | | — | | 5.0 | | 3.9 | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | — | | — | | 4.0 | | 3.1 | | — | | — | | — | | — | | — | | — | | — | | — | |
Total Proved | | — | | — | | 9.0 | | 7.0 | | — | | — | | — | | — | | — | | — | | — | | — | |
Total Probable | | — | | — | | 13.1 | | 10.2 | | — | | — | | — | | — | | — | | — | | — | | — | |
Total Proved Plus Probable | | — | | — | | 22.1 | | 17.2 | | — | | — | | — | | — | | — | | — | | — | | — | |
Other(4) | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 12.7 | | 6.9 | | — | | — | | — | | — | | — | | — | | — | | — | | 2.0 | | 1.0 | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 1.4 | | 0.7 | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Total Proved | | 14.1 | | 7.6 | | — | | — | | — | | — | | — | | — | | — | | — | | 2.0 | | 1.0 | |
Total Probable | | 11.7 | | 6.1 | | — | | — | | — | | — | | — | | — | | — | | — | | 0.3 | | 0.1 | |
Total Proved Plus Probable | | 25.8 | | 13.7 | | — | | — | | — | | — | | — | | — | | — | | — | | 2.3 | | 1.1 | |
TOTAL CONSOLIDATED ENTITIES | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 30.4 | | 20.1 | | 31.4 | | 27.1 | | 4.4 | | 3.3 | | 1,253.6 | | 1,055.9 | | 1,264.5 | | 1,002.5 | | 55.3 | | 39.9 | |
Proved Developed Non-Producing | | 0.1 | | 0.1 | | — | | — | | — | | — | | 26.0 | | 21.9 | | 68.6 | | 49.1 | | 0.4 | | 0.4 | |
Proved Undeveloped | | 1.4 | | 0.7 | | 4.4 | | 3.5 | | 5.0 | | 3.8 | | 698.7 | | 584.3 | | 244.6 | | 182.4 | | 21.9 | | 16.5 | |
Total Proved | | 31.9 | | 20.9 | | 35.8 | | 30.6 | | 9.4 | | 7.1 | | 1,978.3 | | 1,662.1 | | 1,577.7 | | 1,234.0 | | 77.6 | | 56.8 | |
Total Probable | | 76.0 | | 54.7 | | 20.5 | | 16.7 | | 2.1 | | 1.6 | | 777.2 | | 658.1 | | 863.5 | | 689.8 | | 30.5 | | 21.4 | |
Total Proved Plus Probable | | 107.9 | | 75.6 | | 56.3 | | 47.3 | | 11.5 | | 8.7 | | 2,755.5 | | 2,320.2 | | 2,441.2 | | 1,923.8 | | 108.1 | | 78.2 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | | | | | | | | | | | | | |
TSEUK | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 22.5 | | 22.5 | | — | | — | | — | | — | | — | | — | | 0.9 | | 0.9 | | — | | — | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 7.4 | | 7.4 | | — | | — | | — | | — | | — | | — | | 27.2 | | 27.2 | | — | | — | |
Total Proved | | 29.9 | | 29.9 | | — | | — | | — | | — | | — | | — | | 28.1 | | 28.1 | | — | | — | |
Total Probable | | 29.0 | | 29.0 | | — | | — | | — | | — | | — | | — | | 17.9 | | 17.9 | | 0.1 | | 0.1 | |
Total Proved Plus Probable | | 58.9 | | 58.9 | | — | | — | | — | | — | | — | | — | | 46.0 | | 46.0 | | 0.1 | | 0.1 | |
Equion | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 7.8 | | 6.2 | | — | | — | | — | | — | | — | | — | | 42.0 | | 42.0 | | 1.5 | | 1.5 | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 0.6 | | 0.4 | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Total Proved | | 8.4 | | 6.6 | | — | | — | | — | | — | | — | | — | | 42.0 | | 42.0 | | 1.5 | | 1.5 | |
Total Probable | | 3.1 | | 2.5 | | — | | — | | — | | — | | — | | — | | 1.5 | | 1.5 | | 0.1 | | 0.1 | |
Total Proved Plus Probable | | 11.5 | | 9.1 | | — | | — | | — | | — | | — | | — | | 43.5 | | 43.5 | | 1.6 | | 1.6 | |
TOTAL EQUITY INVESTMENTS | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 30.3 | | 28.7 | | — | | — | | — | | — | | — | | — | | 42.9 | | 42.9 | | 1.5 | | 1.5 | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 8.0 | | 7.8 | | — | | — | | — | | — | | — | | — | | 27.2 | | 27.2 | | — | | — | |
Total Proved | | 38.3 | | 36.5 | | — | | — | | — | | — | | — | | — | | 70.1 | | 70.1 | | 1.5 | | 1.5 | |
Total Probable | | 32.1 | | 31.5 | | — | | — | | — | | — | | — | | — | | 19.4 | | 19.4 | | 0.2 | | 0.2 | |
Total Proved Plus Probable | | 70.4 | | 68.0 | | — | | — | | — | | — | | — | | — | | 89.5 | | 89.5 | | 1.7 | | 1.7 | |
TOTAL ROGCI(5) | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 60.7 | | 48.8 | | 31.4 | | 27.1 | | 4.4 | | 3.3 | | 1,253.6 | | 1,055.9 | | 1,307.4 | | 1,045.4 | | 56.8 | | 41.4 | |
Proved Developed Non-Producing | | 0.1 | | 0.1 | | — | | — | | — | | — | | 26.0 | | 21.9 | | 68.6 | | 49.1 | | 0.4 | | 0.4 | |
Proved Undeveloped | | 9.4 | | 8.5 | | 4.4 | | 3.5 | | 5.0 | | 3.8 | | 698.7 | | 584.3 | | 271.8 | | 209.6 | | 21.9 | | 16.5 | |
Total Proved | | 70.2 | | 57.4 | | 35.8 | | 30.6 | | 9.4 | | 7.1 | | 1,978.3 | | 1,662.1 | | 1,647.8 | | 1,304.1 | | 79.1 | | 58.3 | |
Total Probable | | 108.1 | | 86.2 | | 20.5 | | 16.7 | | 2.1 | | 1.6 | | 777.2 | | 658.1 | | 882.9 | | 709.2 | | 30.7 | | 21.6 | |
Total Proved Plus Probable | | 178.3 | | 143.6 | | 56.3 | | 47.3 | | 11.5 | | 8.7 | | 2,755.5 | | 2,320.2 | | 2,530.7 | | 2,013.3 | | 109.8 | | 79.9 | |
(1) The prices used for the estimates of reserves are set forth under “Pricing Assumptions” later in this section.
(2) Southeast Asia includes Indonesia, Malaysia, Vietnam, Australia/Timor-Leste and Papua New Guinea.
(3) Latin America does not include any reserves attributable to the Company’s investment in Equion, shown separately under “Equity Investments” in this table.
(4) Other refers to Algeria.
(5) Total Consolidated Entities plus Total Equity Investments.
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Net Present Value of Future Net Revenue(1)
| | Before Deducting Income Taxes
Discounted At | | After Deducting Income Taxes
Discounted At(2) | |
Year ended December 31, 2015 | | 0% | | 5% | | 10% | | 15% | | 20% | | 0% | | 5% | | 10% | | 15% | | 20% | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 83.4 | | 966.5 | | 856.6 | | 707.6 | | 593.4 | | 70.0 | | 962.4 | | 855.2 | | 707.2 | | 593.2 | |
Proved Developed Non-Producing | | (4.4 | ) | 11.0 | | 10.5 | | 9.0 | | 7.6 | | (4.3 | ) | 11.0 | | 10.6 | | 9.0 | | 7.7 | |
Proved Undeveloped | | 169.5 | | 101.1 | | 58.7 | | 32.1 | | 14.9 | | 169.8 | | 101.1 | | 58.7 | | 32.0 | | 14.8 | |
Total Proved | | 248.5 | | 1,078.6 | | 925.8 | | 748.7 | | 615.9 | | 235.5 | | 1,074.5 | | 924.5 | | 748.2 | | 615.7 | |
Total Probable | | 1,212.1 | | 624.5 | | 376.7 | | 252.3 | | 181.4 | | 967.4 | | 516.2 | | 325.2 | | 226.3 | | 167.6 | |
Total Proved Plus Probable | | 1,460.6 | | 1,703.1 | | 1,302.5 | | 1,001.0 | | 797.3 | | 1,202.9 | | 1,590.7 | | 1,249.7 | | 974.5 | | 783.3 | |
United States | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 3,410.4 | | 2,443.7 | | 1,823.2 | | 1,437.4 | | 1,183.0 | | 2,760.9 | | 2,016.4 | | 1,505.1 | | 1,182.2 | | 968.3 | |
Proved Developed Non-Producing | | (89.6 | ) | 26.9 | | 30.0 | | 24.7 | | 20.1 | | (104.5 | ) | 18.0 | | 23.9 | | 19.9 | | 16.2 | |
Proved Undeveloped | | 2,309.5 | | 1,289.6 | | 787.3 | | 501.9 | | 324.0 | | 1,583.0 | | 892.8 | | 540.2 | | 332.7 | | 199.5 | |
Total Proved | | 5,630.3 | | 3,760.2 | | 2,640.5 | | 1,964.0 | | 1,527.1 | | 4,239.4 | | 2,927.2 | | 2,069.2 | | 1,534.8 | | 1,184.0 | |
Total Probable | | 3,100.9 | | 1,187.4 | | 610.1 | | 367.4 | | 239.3 | | 2,115.1 | | 739.8 | | 340.3 | | 179.7 | | 98.4 | |
Total Proved Plus Probable | | 8,731.2 | | 4,947.6 | | 3,250.6 | | 2,331.4 | | 1,766.4 | | 6,354.5 | | 3,667.0 | | 2,409.5 | | 1,714.5 | | 1,282.4 | |
Southeast Asia(3) | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 4,058.9 | | 3,383.3 | | 2,882.1 | | 2,499.0 | | 2,199.1 | | 2,347.6 | | 1,969.0 | | 1,686.9 | | 1,470.5 | | 1,300.3 | |
Proved Developed Non-Producing | | 100.2 | | 92.5 | | 85.8 | | 80.0 | | 74.9 | | 99.1 | | 91.5 | | 84.9 | | 79.1 | | 74.1 | |
Proved Undeveloped | | 1,159.3 | | 747.5 | | 504.6 | | 352.1 | | 251.2 | | 660.7 | | 423.0 | | 282.1 | | 193.0 | | 133.9 | |
Total Proved | | 5,318.4 | | 4,223.3 | | 3,472.5 | | 2,931.1 | | 2,525.2 | | 3,107.4 | | 2,483.5 | | 2,053.9 | | 1,742.6 | | 1,508.3 | |
Total Probable | | 4,120.4 | | 2,832.1 | | 2,012.1 | | 1,462.1 | | 1,078.7 | | 2,493.5 | | 1,681.3 | | 1,160.8 | | 810.9 | | 567.0 | |
Total Proved Plus Probable | | 9,438.8 | | 7,055.4 | | 5,484.6 | | 4,393.2 | | 3,603.9 | | 5,600.9 | | 4,164.8 | | 3,214.7 | | 2,553.5 | | 2,075.3 | |
Latin America(4) | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 6.2 | | 4.1 | | 2.3 | | 0.7 | | (0.5 | ) | 4.7 | | 2.7 | | 1.0 | | (0.4 | ) | (1.6 | ) |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 10.1 | | 6.3 | | 3.0 | | 0.3 | | (2.1 | ) | 5.7 | | 2.8 | | 0.1 | | (2.2 | ) | (4.2 | ) |
Total Proved | | 16.3 | | 10.4 | | 5.3 | | 1.0 | | (2.6 | ) | 10.4 | | 5.5 | | 1.1 | | (2.6 | ) | (5.8 | ) |
Total Probable | | 191.7 | | 142.4 | | 106.3 | | 79.6 | | 59.6 | | 147.5 | | 109.0 | | 80.6 | | 59.5 | | 43.8 | |
Total Proved Plus Probable | | 208.0 | | 152.8 | | 111.6 | | 80.6 | | 57.0 | | 157.9 | | 114.5 | | 81.7 | | 56.9 | | 38.0 | |
Other(5) | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 285.6 | | 237.1 | | 200.7 | | 172.8 | | 150.8 | | 176.0 | | 147.8 | | 126.5 | | 109.9 | | 96.9 | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 55.2 | | 44.3 | | 36.4 | | 30.5 | | 26.0 | | 31.5 | | 25.2 | | 20.6 | | 17.3 | | 14.6 | |
Total Proved | | 340.8 | | 281.4 | | 237.1 | | 203.3 | | 176.8 | | 207.5 | | 173.0 | | 147.1 | | 127.2 | | 111.5 | |
Total Probable | | 378.3 | | 290.2 | | 229.1 | | 185.3 | | 153.1 | | 215.8 | | 164.7 | | 129.3 | | 104.1 | | 85.6 | |
Total Proved Plus Probable | | 719.1 | | 571.6 | | 466.2 | | 388.6 | | 329.9 | | 423.3 | | 337.7 | | 276.4 | | 231.3 | | 197.1 | |
TOTAL CONSOLIDATED ENTITIES | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 7,844.5 | | 7,034.7 | | 5,764.9 | | 4,817.5 | | 4,125.8 | | 5,359.2 | | 5,098.3 | | 4,174.7 | | 3,469.4 | | 2,957.1 | |
Proved Developed Non-Producing | | 6.2 | | 130.4 | | 126.3 | | 113.7 | | 102.6 | | (9.7 | ) | 120.5 | | 119.4 | | 108.0 | | 98.0 | |
Proved Undeveloped | | 3,703.6 | | 2,188.8 | | 1,390.0 | | 916.9 | | 614.0 | | 2,450.7 | | 1,444.9 | | 901.7 | | 572.8 | | 358.6 | |
Total Proved | | 11,554.3 | | 9,353.9 | | 7,281.2 | | 5,848.1 | | 4,842.4 | | 7,800.2 | | 6,663.7 | | 5,195.8 | | 4,150.2 | | 3,413.7 | |
Total Probable | | 9,003.4 | | 5,076.6 | | 3,334.3 | | 2,346.7 | | 1,712.1 | | 5,939.3 | | 3,211.0 | | 2,036.2 | | 1,380.5 | | 962.4 | |
Total Proved Plus Probable | | 20,557.7 | | 14,430.5 | | 10,615.5 | | 8,194.8 | | 6,554.5 | | 13,739.5 | | 9,874.7 | | 7,232.0 | | 5,530.7 | | 4,376.1 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | | | | | | | | | |
TSEUK | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | (4,909.4 | ) | (3,195.4 | ) | (2,280.9 | ) | (1,745.7 | ) | (1,406.7 | ) | (3,823.7 | ) | (2,498.6 | ) | (1,798.4 | ) | (1,393.0 | ) | (1,138.6 | ) |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 126.7 | | 92.0 | | 55.6 | | 24.1 | | (1.8 | ) | 126.4 | | 84.6 | | 45.8 | | 13.9 | | (11.2 | ) |
Total Proved | | (4,782.7 | ) | (3,103.4 | ) | (2,225.3 | ) | (1,721.6 | ) | (1,408.5 | ) | (3,697.3 | ) | (2,414.0 | ) | (1,752.6 | ) | (1,379.1 | ) | (1,149.8 | ) |
Total Probable | | 1,166.2 | | 879.4 | | 685.6 | | 550.4 | | 453.2 | | 1,112.9 | | 765.8 | | 569.3 | | 448.2 | | 367.7 | |
Total Proved Plus Probable | | (3,616.5 | ) | (2,224.0 | ) | (1,539.7 | ) | (1,171.2 | ) | (955.3 | ) | (2,584.4 | ) | (1,648.2 | ) | (1,183.3 | ) | (930.9 | ) | (782.1 | ) |
34
| | Before Deducting Income Taxes
Discounted At | | After Deducting Income Taxes
Discounted At(2) | |
Year ended December 31, 2015 | | 0% | | 5% | | 10% | | 15% | | 20% | | 0% | | 5% | | 10% | | 15% | | 20% | |
Equion | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 302.9 | | 276.0 | | 253.4 | | 234.0 | | 217.4 | | 233.0 | | 212.5 | | 195.1 | | 180.3 | | 167.6 | |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 9.2 | | 7.7 | | 6.3 | | 5.3 | | 4.4 | | 4.9 | | 3.7 | | 2.8 | | 2.0 | | 1.3 | |
Total Proved | | 312.1 | | 283.7 | | 259.7 | | 239.3 | | 221.8 | | 237.9 | | 216.2 | | 197.9 | | 182.3 | | 168.9 | |
Total Probable | | 122.6 | | 109.4 | | 98.6 | | 89.4 | | 81.6 | | 77.0 | | 68.3 | | 61.2 | | 55.3 | | 50.3 | |
Total Proved Plus Probable | | 434.7 | | 393.1 | | 358.3 | | 328.7 | | 303.4 | | 314.9 | | 284.5 | | 259.1 | | 237.6 | | 219.2 | |
TOTAL EQUITY INVESTMENTS | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | (4,606.5 | ) | (2,919.4 | ) | (2,027.5 | ) | (1,511.7 | ) | (1,189.3 | ) | (3,590.7 | ) | (2,286.1 | ) | (1,603.3 | ) | (1,212.7 | ) | (971.0 | ) |
Proved Developed Non-Producing | | — | | — | | — | | — | | — | | — | | — | | — | | — | | — | |
Proved Undeveloped | | 135.9 | | 99.7 | | 61.9 | | 29.4 | | 2.6 | | 131.3 | | 88.3 | | 48.6 | | 15.9 | | (9.9 | ) |
Total Proved | | (4,470.6 | ) | (2,819.7 | ) | (1,965.6 | ) | (1,482.3 | ) | (1,186.7 | ) | (3,459.4 | ) | (2,197.8 | ) | (1,554.7 | ) | (1,196.8 | ) | (980.9 | ) |
Total Probable | | 1,288.8 | | 988.8 | | 784.2 | | 639.8 | | 534.8 | | 1,189.9 | | 834.1 | | 630.5 | | 503.5 | | 418.0 | |
Total Proved Plus Probable | | (3,181.8 | ) | (1,830.9 | ) | (1,181.4 | ) | (842.5 | ) | (651.9 | ) | (2,269.5 | ) | (1,363.7 | ) | (924.2 | ) | (693.3 | ) | (562.9 | ) |
TOTAL ROGCI(6) | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Producing | | 3,238.0 | | 4,115.3 | | 3,737.4 | | 3,305.8 | | 2,936.5 | | 1,768.5 | | 2,812.2 | | 2,571.4 | | 2,256.7 | | 1,986.1 | |
Proved Developed Non-Producing | | 6.2 | | 130.4 | | 126.3 | | 113.7 | | 102.6 | | (9.7 | ) | 120.5 | | 119.4 | | 108.0 | | 98.0 | |
Proved Undeveloped | | 3,839.5 | | 2,288.5 | | 1,451.9 | | 946.3 | | 616.6 | | 2,582.0 | | 1,533.2 | | 950.3 | | 588.7 | | 348.7 | |
Total Proved | | 7,083.7 | | 6,534.2 | | 5,315.6 | | 4,365.8 | | 3,655.7 | | 4,340.8 | | 4,465.9 | | 3,641.1 | | 2,953.4 | | 2,432.8 | |
Total Probable | | 10,292.2 | | 6,065.4 | | 4,118.5 | | 2,986.5 | | 2,246.9 | | 7,129.2 | | 4,045.1 | | 2,666.7 | | 1,884.0 | | 1,380.4 | |
Total Proved Plus Probable | | 17,375.9 | | 12,599.6 | | 9,434.1 | | 7,352.3 | | 5,902.6 | | 11,470.0 | | 8,511.0 | | 6,307.8 | | 4,837.4 | | 3,813.2 | |
(1) The prices used for the estimates of future net revenue are set forth under “Pricing Assumptions” later in this section.
(2) Future Net Revenue After Deducting Income Taxes has been calculated by deducting royalties and taxes which have been computed separately for each taxable entity using existing tax pool balances using tax pool write-off rates and tax rates and rules in accordance with existing legislation. No benefit has been included for future interest expense or the benefits of future tax planning opportunities. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, see the Company’s Consolidated Financial Statements and Management’s Discussion and Analysis for the year ended December 31, 2015.
(3) Southeast Asia includes Indonesia, Malaysia, Vietnam and Australia/Timor-Leste and Papua New Guinea.
(4) Latin America does not include any future net revenue attributable to the Company’s investment in Equion, shown separately under “Equity Investments” in this table.
(5) Other refers to Algeria.
(6) Total Consolidated Entities plus Total Equity Investments.
35
Elements of Future Net Revenue
(Undiscounted) ($ Millions)
Year ended December 31, 2015 | | Revenue | | Royalties | | Operating
Costs | | Development
Costs | | Abandonment
and Reclamation
Costs | | Future Net
Revenue Before
Taxes | | Taxes(1) | | Future Net
Revenue After
Taxes | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | | | | | |
Proved | | 5,899.4 | | 613.7 | | 2,643.8 | | 512.3 | | 1,881.1 | | 248.5 | | 13.0 | | 235.5 | |
Proved Plus Probable | | 8,524.1 | | 961.8 | | 3,556.3 | | 610.0 | | 1,935.4 | | 1,460.6 | | 257.7 | | 1,202.9 | |
United States | | | | | | | | | | | | | | | | | |
Proved | | 12,271.0 | | 2,130.4 | | 3,092.1 | | 918.7 | | 499.5 | | 5,630.3 | | 1,390.9 | | 4,239.4 | |
Proved Plus Probable | | 18,463.9 | | 3,167.4 | | 4,728.7 | | 1,266.4 | | 570.2 | | 8,731.2 | | 2,376.7 | | 6,354.5 | |
Southeast Asia | | | | | | | | | | | | | | | | | |
Proved | | 7,570.6 | | — | | 1,746.3 | | 301.5 | | 204.4 | | 5,318.4 | | 2,211.0 | | 3,107.4 | |
Proved Plus Probable | | 16,642.1 | | — | | 4,748.6 | | 1,841.1 | | 613.6 | | 9,438.8 | | 3,837.9 | | 5,600.9 | |
Latin America | | | | | | | | | | | | | | | | | |
Proved | | 381.5 | | — | | 324.7 | | 28.0 | | 12.5 | | 16.3 | | 5.9 | | 10.4 | |
Proved Plus Probable | | 1,084.7 | | — | | 762.6 | | 96.8 | | 17.3 | | 208.0 | | 50.1 | | 157.9 | |
Other | | | | | | | | | | | | | | | | | |
Proved | | 559.8 | | — | | 201.5 | | 2.9 | | 14.6 | | 340.8 | | 133.3 | | 207.5 | |
Proved Plus Probable | | 1,036.7 | | — | | 251.8 | | 51.2 | | 14.6 | | 719.1 | | 295.8 | | 423.3 | |
TOTAL CONSOLIDATED ENTITIES | | | | | | | | | | | | | | | | | |
Proved | | 26,682.3 | | 2,744.1 | | 8,008.4 | | 1,763.4 | | 2,612.1 | | 11,554.3 | | 3,754.1 | | 7,800.2 | |
Proved Plus Probable | | 45,751.5 | | 4,129.2 | | 14,048.0 | | 3,865.5 | | 3,151.1 | | 20,557.7 | | 6,818.2 | | 13,739.5 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | | | | | |
TSEUK | | | | | | | | | | | | | | | | | |
Proved | | 2,339.9 | | — | | 2,497.0 | | 605.6 | | 4,020.0 | | (4,782.7 | ) | (1,085.4 | ) | (3,697.3 | ) |
Proved Plus Probable | | 5,003.8 | | 0.2 | | 3,920.0 | | 680.1 | | 4,020.0 | | (3,616.5 | ) | (1,032.1 | ) | (2,584.4 | ) |
EQUION | | | | | | | | | | | | | | | | | |
Proved | | 536.1 | | 37.9 | | 162.3 | | 13.4 | | 10.4 | | 312.1 | | 74.2 | | 237.9 | |
Proved Plus Probable | | 685.3 | | 39.4 | | 187.4 | | 13.4 | | 10.4 | | 434.7 | | 119.8 | | 314.9 | |
TOTAL EQUITY INVESTMENTS | | | | | | | | | | | | | | | | | |
Proved | | 2,876.0 | | 37.9 | | 2,659.3 | | 619.0 | | 4,030.4 | | (4,470.6 | ) | (1,011.2 | ) | (3,459.4 | ) |
Proved Plus Probable | | 5,689.1 | | 39.6 | | 4,107.4 | | 693.5 | | 4,030.4 | | (3,181.8 | ) | (912.3 | ) | (2,269.5 | ) |
TOTAL ROGCI(2) | | | | | | | | | | | | | | | | | |
Proved | | 29,558.3 | | 2,782.0 | | 10,667.7 | | 2,382.4 | | 6,642.5 | | 7,083.7 | | 2,742.9 | | 4,340.8 | |
Proved Plus Probable | | 51,440.6 | | 4,168.8 | | 18,155.4 | | 4,559.0 | | 7,181.5 | | 17,375.9 | | 5,905.9 | | 11,470.0 | |
(1) Income Taxes include Petroleum Revenue Tax.
(2) Total Consolidated Entities plus Total Equity Investments.
36
Future Net Revenue by Production Group(1)
| | | | Future Net
Revenue Before
Income Taxes
(Discounted at
10%/year) | | | |
Reserves Category | | Production Group | | ($ Millions) | | Per Unit | |
CONSOLIDATED ENTITIES | | | | | | | |
Proved Reserves | | | | | | | |
| | Light Oil | | 568.2 | | $ | 12.62 / bbl | |
| | Non-Shale Natural Gas | | 3,465.7 | | $ | 1.96 / mcf | |
| | Natural Gas Liquids | | 887.2 | | $ | 9.28 / bbl | |
| | Shale Gas | | 1,841.0 | | $ | 0.89 / mcf | |
| | Tight Oil | | 244.5 | | $ | 20.29 / bbl | |
| | Heavy Oil | | 275.0 | | $ | 8.08 / bbl | |
Proved Plus Probable | | | | | | | |
| | Light Oil | | 2,045.8 | | $ | 14.57 / bbl | |
| | Non-Shale Natural Gas | | 4,399.5 | | $ | 1.65 / mcf | |
| | Natural Gas Liquids | | 1,072.7 | | $ | 8.43 / bbl | |
| | Shale Gas | | 2,382.9 | | $ | 0.82 / mcf | |
| | Tight Oil | | 258.6 | | $ | 18.16 / bbl | |
| | Heavy Oil | | 456.8 | | $ | 7.99 / bbl | |
EQUITY INVESTMENTS | | | | | | | |
Proved Reserves | | | | | | | |
| | Light Oil | | (1,658.7 | ) | $ | -56.79 / bbl | |
| | Non-Shale Natural Gas | | (312.3 | ) | $ | -3.85 / mcf | |
| | Natural Gas Liquids | | 5.4 | | $ | 2.58 / bbl | |
| | Shale Gas | | — | | $ | 0.00 / mcf | |
| | Tight Oil | | — | | $ | 0.00 / bbl | |
| | Heavy Oil | | — | | $ | 0.00 / bbl | |
Proved Plus Probable | | | | | | | |
| | Light Oil | | (970.2 | ) | $ | -10.64 / bbl | |
| | Non-Shale Natural Gas | | (217.8 | ) | $ | -1.89 / mcf | |
| | Natural Gas Liquids | | 6.8 | | $ | 2.97 / bbl | |
| | Shale Gas | | — | | $ | 0.00 / mcf | |
| | Tight Oil | | — | | $ | 0.00 / bbl | |
| | Heavy Oil | | — | | $ | 0.00 / bbl | |
(1) Includes the Company’s interest in future net revenue attributable to TSEUK and Equion.
37
Reconciliation of Changes in Reserves
Continuity of Gross Proved Reserves
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | |
At December 31, 2014 | | 2.8 | | 25.5 | | — | | 28.9 | | 439.6 | | 26.7 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | 0.3 | | 0.8 | | — | | 19.2 | | 72.2 | | 6.3 | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | (0.3 | ) | — | |
Technical Revisions | | (0.3 | ) | 1.7 | | — | | (1.4 | ) | 5.0 | | (1.2 | ) |
Economic Revisions | | — | | 2.2 | | — | | 1.4 | | (0.3 | ) | 0.1 | |
Production(1) | | (0.6 | ) | (3.4 | ) | — | | (4.7 | ) | (75.2 | ) | (4.2 | ) |
At December 31, 2015 | | 2.2 | | 26.8 | | — | | 43.4 | | 441.0 | | 27.7 | |
United States | | | | | | | | | | | | | |
At December 31, 2014 | | — | | — | | 12.1 | | 2,042.1 | | 29.0 | | 54.9 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | 2.1 | | 299.1 | | — | | 11.8 | |
Acquisitions | | — | | — | | — | | 22.9 | | — | | — | |
Divestment | | — | | — | | (3.4 | ) | (63.9 | ) | (1.0 | ) | (13.9 | ) |
Technical Revisions | | — | | — | | 0.6 | | 63.5 | | 2.2 | | (5.8 | ) |
Economic Revisions | | — | | — | | (0.5 | ) | (220.4 | ) | (10.2 | ) | (2.5 | ) |
Production(1) | | — | | — | | (1.5 | ) | (208.4 | ) | (3.9 | ) | (5.8 | ) |
At December 31, 2015 | | — | | — | | 9.4 | | 1,934.9 | | 16.1 | | 38.7 | |
North Sea(2) | | | | | | | | | | | | | |
At December 31, 2014 | | 3.2 | | — | | — | | — | | 6.8 | | 0.8 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | (1.7 | ) | — | | — | | — | | (3.5 | ) | (0.4 | ) |
Technical Revisions | | 1.4 | | — | | — | | — | | 1.9 | | — | |
Economic Revisions | | — | | — | | — | | — | | — | | — | |
Production(1) | | (2.9 | ) | — | | — | | — | | (5.2 | ) | (0.4 | ) |
At December 31, 2015 | | — | | — | | — | | — | | — | | — | |
South East Asia | | | | | | | | | | | | | |
At December 31, 2014 | | 23.5 | | — | | — | | — | | 1,295.7 | | 11.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | 27.5 | | 0.2 | |
Acquisitions | | 0.2 | | — | | — | | — | | 5.8 | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 3.2 | | — | | — | | — | | (27.8 | ) | 0.1 | |
Economic Revisions | | (0.5 | ) | — | | — | | — | | (3.4 | ) | — | |
Production(1) | | (10.8 | ) | — | | — | | — | | (177.2 | ) | (2.2 | ) |
At December 31, 2015 | | 15.6 | | — | | — | | — | | 1,120.6 | | 9.2 | |
38
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
Latin America(3) | | | | | | | | | | | | | |
At December 31, 2014 | | — | | 9.2 | | — | | — | | — | | — | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | 0.2 | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | — | | 1.3 | | — | | — | | — | | — | |
Economic Revisions | | — | | (0.6 | ) | — | | — | | — | | — | |
Production(1) | | — | | (1.1 | ) | — | | — | | — | | — | |
At December 31, 2015 | | — | | 9.0 | | — | | — | | — | | — | |
Other | | | | | | | | | | | | | |
At December 31, 2014 | | 14.8 | | — | | — | | — | | — | | 2.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 3.3 | | — | | — | | — | | — | | (0.1 | ) |
Economic Revisions | | — | | — | | — | | — | | — | | — | |
Production(1) | | (4.0 | ) | — | | — | | — | | — | | — | |
At December 31, 2015 | | 14.1 | | — | | — | | — | | — | | 2.0 | |
TOTAL CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
At December 31, 2014 | | 44.3 | | 34.7 | | 12.1 | | 2,071.0 | | 1,771.1 | | 95.6 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | 0.3 | | 1.0 | | 2.1 | | 318.3 | | 99.7 | | 18.3 | |
Acquisitions | | 0.2 | | — | | — | | 22.9 | | 5.8 | | — | |
Divestment | | (1.7 | ) | — | | (3.4 | ) | (63.9 | ) | (4.8 | ) | (14.3 | ) |
Technical Revisions | | 7.6 | | 3.0 | | 0.6 | | 62.1 | | (18.7 | ) | (7.0 | ) |
Economic Revisions | | (0.5 | ) | 1.6 | | (0.5 | ) | (219.0 | ) | (13.9 | ) | (2.4 | ) |
Production(1) | | (18.3 | ) | (4.5 | ) | (1.5 | ) | (213.1 | ) | (261.5 | ) | (12.6 | ) |
At December 31, 2015 | | 31.9 | | 35.8 | | 9.4 | | 1,978.3 | | 1,577.7 | | 77.6 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | |
TSEUK | | | | | | | | | | | | | |
At December 31, 2014 | | 18.6 | | — | | — | | — | | 25.0 | | 0.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 8.3 | | — | | — | | — | | 0.4 | | (0.1 | ) |
Economic Revisions | | 10.2 | | — | | — | | — | | 4.0 | | — | |
Production(1) | | (7.2 | ) | — | | — | | — | | (1.3 | ) | — | |
At December 31, 2015 | | 29.9 | | — | | — | | — | | 28.1 | | — | |
Equion | | | | | | | | | | | | | |
At December 31, 2014 | | 10.6 | | — | | — | | — | | 56.2 | | 2.0 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | 2.5 | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 2.0 | | — | | — | | — | | (1.6 | ) | — | |
Economic Revisions | | (0.2 | ) | — | | — | | — | | — | | — | |
Production(1) | | (4.0 | ) | — | | — | | — | | (15.1 | ) | (0.5 | ) |
At December 31, 2015 | | 8.4 | | — | | — | | — | | 42.0 | | 1.5 | |
39
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
TOTAL EQUITY INVESTMENTS | | | | | | | | | | | | | |
At December 31, 2014 | | 29.2 | | — | | — | | — | | 81.2 | | 2.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | 2.5 | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 10.3 | | — | | — | | — | | (1.2 | ) | (0.1 | ) |
Economic Revisions | | 10.0 | | — | | — | | — | | 4.0 | | — | |
Production(1) | | (11.2 | ) | — | | — | | — | | (16.4 | ) | (0.5 | ) |
At December 31, 2015 | | 38.3 | | — | | — | | — | | 70.1 | | 1.5 | |
TOTAL ROGCI | | | | | | | | | | | | | |
Discoveries | | 73.5 | | 34.7 | | 12.1 | | 2,071.0 | | 1,852.3 | | 97.7 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | 0.3 | | 1.0 | | 2.1 | | 318.3 | | 102.2 | | 18.3 | |
Acquisitions | | 0.2 | | — | | — | | 22.9 | | 5.8 | | — | |
Divestment | | (1.7 | ) | — | | (3.4 | ) | (63.9 | ) | (4.8 | ) | (14.3 | ) |
Technical Revisions | | 17.9 | | 3.0 | | 0.6 | | 62.1 | | (19.9 | ) | (7.1 | ) |
Economic Revisions | | 9.5 | | 1.6 | | (0.5 | ) | (219.0 | ) | (9.9 | ) | (2.4 | ) |
Production(1) | | (29.5 | ) | (4.5 | ) | (1.5 | ) | (213.1 | ) | (277.9 | ) | (13.1 | ) |
At December 31, 2015 | | 70.2 | | 35.8 | | 9.4 | | 1,978.3 | | 1,647.8 | | 79.1 | |
(1) Production numbers reflect the best estimate of calendar year production and do not include out of period accounting adjustments.
(2) North Sea does not include any reserves attributable to the Company’s investment in TSEUK, shown separately under “Equity Investments” in this table.
(3) Latin America does not include any reserves attributable to the Company’s investment in Equion, shown separately under “Equity Investments” in this table.
40
Continuity of Gross Probable Reserves
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | |
At December 31, 2014 | | 0.9 | | 7.6 | | — | | 12.0 | | 150.1 | | 10.2 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | 0.1 | | 0.4 | | — | | 11.6 | | 16.9 | | 3.0 | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | (0.2 | ) | 0.1 | | — | | 3.2 | | (5.8 | ) | (0.2 | ) |
Economic Revisions | | — | | (0.7 | ) | — | | 0.5 | | 0.7 | | (0.1 | ) |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | 0.8 | | 7.4 | | — | | 27.3 | | 161.9 | | 12.9 | |
United States | | | | | | | | | | | | | |
At December 31, 2014 | | — | | — | | 2.2 | | 826.1 | | 9.5 | | 13.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | 0.3 | | 109.2 | | — | | 2.1 | |
Acquisitions | | — | | — | | — | | 7.6 | | — | | — | |
Divestment | | — | | — | | (0.8 | ) | (16.4 | ) | (0.4 | ) | (3.5 | ) |
Technical Revisions | | — | | — | | 0.3 | | 17.5 | | 0.9 | | (1.0 | ) |
Economic Revisions | | — | | — | | 0.1 | | (194.1 | ) | 0.1 | | (0.6 | ) |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | — | | — | | 2.1 | | 749.9 | | 10.1 | | 10.1 | |
North Sea(2) | | | | | | | | | | | | | |
At December 31, 2014 | | 6.1 | | — | | — | | — | | 15.9 | | 1.7 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | (5.2 | ) | — | | — | | — | | (14.0 | ) | (1.7 | ) |
Technical Revisions | | (0.9 | ) | — | | — | | — | | (1.9 | ) | — | |
Economic Revisions | | — | | — | | — | | — | | — | | — | |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | — | | — | | — | | — | | — | | — | |
South East Asia | | | | | | | | | | | | | |
At December 31, 2014 | | 73.6 | | — | | — | | — | | 723.0 | | 6.3 | |
Discoveries | | 1.1 | | — | | — | | — | | 83.9 | | — | |
Additions & Extensions | | — | | — | | — | | — | | (18.6 | ) | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | (0.2 | ) | — | | — | | — | | (51.5 | ) | 1.1 | |
Economic Revisions | | (11.0 | ) | — | | — | | — | | (45.3 | ) | (0.2 | ) |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | 63.5 | | — | | — | | — | | 691.5 | | 7.2 | |
Latin America(3) | | | | | | | | | | | | | |
At December 31, 2014 | | — | | 15.9 | | — | | — | | — | | — | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | (0.2 | ) | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | — | | (2.2 | ) | — | | — | | — | | — | |
Economic Revisions | | — | | (0.4 | ) | — | | — | | — | | — | |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | — | | 13.1 | | — | | — | | — | | — | |
41
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
Other | | | | | | | | | | | | | |
At December 31, 2014 | | 14.2 | | — | | — | | — | | — | | 0.3 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | (2.5 | ) | — | | — | | — | | — | | — | |
Economic Revisions | | — | | — | | — | | — | | — | | — | |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | 11.7 | | — | | — | | — | | — | | 0.3 | |
TOTAL CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
At December 31, 2014 | | 94.8 | | 23.5 | | 2.2 | | 838.1 | | 898.5 | | 31.6 | |
Discoveries | | 1.1 | | — | | — | | — | | 83.9 | | — | |
Additions & Extensions | | 0.1 | | 0.2 | | 0.3 | | 120.8 | | (1.7 | ) | 5.1 | |
Acquisitions | | — | | — | | — | | 7.6 | | — | | — | |
Divestment | | (5.2 | ) | — | | (0.8 | ) | (16.4 | ) | (14.4 | ) | (5.2 | ) |
Technical Revisions | | (3.8 | ) | (2.1 | ) | 0.3 | | 20.7 | | (58.3 | ) | (0.1 | ) |
Economic Revisions | | (11.0 | ) | (1.1 | ) | 0.1 | | (193.6 | ) | (44.5 | ) | (0.9 | ) |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | 76.0 | | 20.5 | | 2.1 | | 777.2 | | 863.5 | | 30.5 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | |
TSEUK | | | | | | | | | | | | | |
At December 31, 2014 | | 57.2 | | — | | — | | — | | 29.5 | | — | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | (3.1 | ) | — | | — | | — | | (0.1 | ) | 0.1 | |
Economic Revisions | | (25.1 | ) | — | | — | | — | | (11.5 | ) | — | |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | 29.0 | | — | | — | | — | | 17.9 | | 0.1 | |
Equion | | | | | | | | | | | | | |
At December 31, 2014 | | 4.8 | | — | | — | | — | | 4.6 | | 0.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | (1.5 | ) | — | | — | | — | | (3.1 | ) | — | |
Economic Revisions | | (0.2 | ) | — | | — | | — | | — | | — | |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | 3.1 | | — | | — | | — | | 1.5 | | 0.1 | |
TOTAL EQUITY INVESTMENTS | | | | | | | | | | | | | |
At December 31, 2014 | | 62.0 | | — | | — | | — | | 34.1 | | 0.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | (4.6 | ) | — | | — | | — | | (3.2 | ) | 0.1 | |
Economic Revisions | | (25.3 | ) | — | | — | | — | | (11.5 | ) | — | |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | 32.1 | | — | | — | | — | | 19.4 | | 0.2 | |
42
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
TOTAL ROGCI | | | | | | | | | | | | | |
At December 31, 2014 | | 156.8 | | 23.5 | | 2.2 | | 838.1 | | 932.6 | | 31.7 | |
Discoveries | | 1.1 | | — | | — | | — | | 83.9 | | — | |
Additions & Extensions | | 0.1 | | 0.2 | | 0.3 | | 120.8 | | (1.7 | ) | 5.1 | |
Acquisitions | | — | | — | | — | | 7.6 | | — | | — | |
Divestment | | (5.2 | ) | — | | (0.8 | ) | (16.4 | ) | (14.4 | ) | (5.2 | ) |
Technical Revisions | | (8.4 | ) | (2.1 | ) | 0.3 | | 20.7 | | (61.5 | ) | — | |
Economic Revisions | | (36.3 | ) | (1.1 | ) | 0.1 | | (193.6 | ) | (56.0 | ) | (0.9 | ) |
Production(1) | | — | | — | | — | | — | | — | | — | |
At December 31, 2015 | | 108.1 | | 20.5 | | 2.1 | | 777.2 | | 882.9 | | 30.7 | |
(1) Production numbers reflect the best estimate of calendar year production and do not include out of period accounting adjustments.
(2) North Sea does not include any reserves attributable to the Company’s investment in TSEUK, shown separately under “Equity Investments” in this table.
(3) Latin America does not include any reserves attributable to the Company’s investment in Equion, shown separately under “Equity Investments” in this table.
43
Continuity of Gross Proved Plus Probable Reserves
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | |
At December 31, 2014 | | 3.7 | | 33.1 | | — | | 40.9 | | 589.7 | | 36.9 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | 0.4 | | 1.2 | | — | | 30.8 | | 89.1 | | 9.3 | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | (0.3 | ) | — | |
Technical Revisions | | (0.5 | ) | 1.8 | | — | | 1.8 | | (0.8 | ) | (1.4 | ) |
Economic Revisions | | — | | 1.5 | | — | | 1.9 | | 0.4 | | — | |
Production(1) | | (0.6 | ) | (3.4 | ) | — | | (4.7 | ) | (75.2 | ) | (4.2 | ) |
At December 31, 2015 | | 3.0 | | 34.2 | | — | | 70.7 | | 602.9 | | 40.6 | |
United States | | | | | | | | | | | | | |
At December 31, 2014 | | — | | — | | 14.3 | | 2,868.2 | | 38.5 | | 68.0 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | 2.4 | | 408.3 | | — | | 13.9 | |
Acquisitions | | — | | — | | — | | 30.5 | | — | | — | |
Divestment | | — | | — | | (4.2 | ) | (80.3 | ) | (1.4 | ) | (17.4 | ) |
Technical Revisions | | — | | — | | 0.9 | | 81.0 | | 3.1 | | (6.8 | ) |
Economic Revisions | | — | | — | | (0.4 | ) | (414.5 | ) | (10.1 | ) | (3.1 | ) |
Production(1) | | — | | — | | (1.5 | ) | (208.4 | ) | (3.9 | ) | (5.8 | ) |
At December 31, 2015 | | — | | — | | 11.5 | | 2,684.8 | | 26.2 | | 48.8 | |
North Sea(2) | | | | | | | | | | | | | |
At December 31, 2014 | | 9.3 | | — | | — | | — | | 22.7 | | 2.5 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | (6.9 | ) | — | | — | | — | | (17.5 | ) | (2.1 | ) |
Technical Revisions | | 0.5 | | — | | — | | — | | — | | — | |
Economic Revisions | | — | | — | | — | | — | | — | | — | |
Production(1) | | (2.9 | ) | — | | — | | — | | (5.2 | ) | (0.4 | ) |
At December 31, 2015 | | — | | — | | — | | — | | — | | — | |
South East Asia | | | | | | | | | | | | | |
At December 31, 2014 | | 97.1 | | — | | — | | — | | 2,018.7 | | 17.4 | |
Discoveries | | 1.1 | | — | | — | | — | | 83.9 | | — | |
Additions & Extensions | | — | | — | | — | | — | | 8.9 | | 0.2 | |
Acquisitions | | 0.2 | | — | | — | | — | | 5.8 | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 3.0 | | — | | — | | — | | (79.3 | ) | 1.2 | |
Economic Revisions | | (11.5 | ) | — | | — | | — | | (48.7 | ) | (0.2 | ) |
Production(1) | | (10.8 | ) | — | | — | | — | | (177.2 | ) | (2.2 | ) |
At December 31, 2015 | | 79.1 | | — | | — | | — | | 1,812.1 | | 16.4 | |
Latin America(3) | | | | | | | | | | | | | |
At December 31, 2014 | | — | | 25.1 | | — | | — | | — | | — | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | — | | (0.9 | ) | — | | — | | — | | — | |
Economic Revisions | | — | | (1.0 | ) | — | | — | | — | | — | |
Production(1) | | — | | (1.1 | ) | — | | — | | — | | — | |
At December 31, 2015 | | — | | 22.1 | | — | | — | | — | | — | |
44
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
Other | | | | | | | | | | | | | |
At December 31, 2014 | | 29.0 | | — | | — | | — | | — | | 2.4 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 0.8 | | — | | — | | — | | — | | (0.1 | ) |
Economic Revisions | | — | | — | | — | | — | | — | | — | |
Production(1) | | (4.0 | ) | — | | — | | — | | — | | — | |
At December 31, 2015 | | 25.8 | | — | | — | | — | | — | | 2.3 | |
TOTAL CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
At December 31, 2014 | | 139.1 | | 58.2 | | 14.3 | | 2,909.1 | | 2,669.6 | | 127.2 | |
Discoveries | | 1.1 | | — | | — | | — | | 83.9 | | — | |
Additions & Extensions | | 0.4 | | 1.2 | | 2.4 | | 439.1 | | 98.0 | | 23.4 | |
Acquisitions | | 0.2 | | — | | — | | 30.5 | | 5.8 | | — | |
Divestment | | (6.9 | ) | — | | (4.2 | ) | (80.3 | ) | (19.2 | ) | (19.5 | ) |
Technical Revisions | | 3.8 | | 0.9 | | 0.9 | | 82.8 | | (77.0 | ) | (7.1 | ) |
Economic Revisions | | (11.5 | ) | 0.5 | | (0.4 | ) | (412.6 | ) | (58.4 | ) | (3.3 | ) |
Production(1) | | (18.3 | ) | (4.5 | ) | (1.5 | ) | (213.1 | ) | (261.5 | ) | (12.6 | ) |
At December 31, 2015 | | 107.9 | | 56.3 | | 11.5 | | 2,755.5 | | 2,441.2 | | 108.1 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | |
TSEUK | | | | | | | | | | | | | |
At December 31, 2014 | | 75.8 | | — | | — | | — | | 54.5 | | 0.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | — | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 5.2 | | — | | — | | — | | 0.3 | | — | |
Economic Revisions | | (14.9 | ) | — | | — | | — | | (7.5 | ) | — | |
Production(1) | | (7.2 | ) | — | | — | | — | | (1.3 | ) | — | |
At December 31, 2015 | | 58.9 | | — | | — | | — | | 46.0 | | 0.1 | |
Equion | | | | | | | | | | | | | |
At December 31, 2014 | | 15.4 | | — | | — | | — | | 60.8 | | 2.1 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | 2.5 | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 0.5 | | — | | — | | — | | (4.7 | ) | — | |
Economic Revisions | | (0.4 | ) | — | | — | | — | | — | | — | |
Production(1) | | (4.0 | ) | — | | — | | — | | (15.1 | ) | (0.5 | ) |
At December 31, 2015 | | 11.5 | | — | | — | | — | | 43.5 | | 1.6 | |
TOTAL EQUITY INVESTMENTS | | | | | | | | | | | | | |
At December 31, 2014 | | 91.2 | | — | | — | | — | | 115.3 | | 2.2 | |
Discoveries | | — | | — | | — | | — | | — | | — | |
Additions & Extensions | | — | | — | | — | | — | | 2.5 | | — | |
Acquisitions | | — | | — | | — | | — | | — | | — | |
Divestment | | — | | — | | — | | — | | — | | — | |
Technical Revisions | | 5.7 | | — | | — | | — | | (4.4 | ) | — | |
Economic Revisions | | (15.3 | ) | — | | — | | — | | (7.5 | ) | — | |
Production(1) | | (11.2 | ) | — | | — | | — | | (16.4 | ) | (0.5 | ) |
At December 31, 2015 | | 70.4 | | — | | — | | — | | 89.5 | | 1.7 | |
45
Year ended December 31, 2015 | | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | NGL
(mmbbls) | |
TOTAL ROGCI | | | | | | | | | | | | | |
At December 31, 2014 | | 230.3 | | 58.2 | | 14.3 | | 2,909.1 | | 2,784.9 | | 129.4 | |
Discoveries | | 1.1 | | — | | — | | — | | 83.9 | | — | |
Additions & Extensions | | 0.4 | | 1.2 | | 2.4 | | 439.1 | | 100.5 | | 23.4 | |
Acquisitions | | 0.2 | | — | | — | | 30.5 | | 5.8 | | — | |
Divestment | | (6.9 | ) | — | | (4.2 | ) | (80.3 | ) | (19.2 | ) | (19.5 | ) |
Technical Revisions | | 9.5 | | 0.90 | | 0.9 | | 82.8 | | (81.4 | ) | (7.1 | ) |
Economic Revisions | | (26.8 | ) | 0.5 | | (0.4 | ) | (412.6 | ) | (65.9 | ) | (3.3 | ) |
Production(1) | | (29.5 | ) | (4.5 | ) | (1.5 | ) | (213.1 | ) | (277.9 | ) | (13.1 | ) |
At December 31, 2015 | | 178.3 | | 56.3 | | 11.5 | | 2,755.5 | | 2,530.7 | | 109.8 | |
(1) Production numbers reflect the best estimate of calendar year production and do not include out of period accounting adjustments.
(2) North Sea does not include any reserves attributable to the Company’s investment in TSEUK, shown separately under “Equity Investments” in this table.
(3) Latin America does not include any reserves attributable to the Company’s investment in Equion, shown separately under “Equity Investments” in this table.
At the end of 2015, the Company’s proved plus probable reserves totaled 1.30 billion boe. The Company added (discoveries, additions, and extensions) approximately 139 million boe (97 million boe proved), plus technical revisions of 8 million boe, negative economic revisions of 119 million boe, and divestments of 49 million boe.
Undeveloped Reserves
The following tables set forth, by product type, the volumes of gross proved undeveloped reserves and gross probable undeveloped reserves that were first attributed as reserves in each of the most recent three financial years. The tables do not include volumes of proved undeveloped and probable undeveloped reserves first attributed in years prior to 2010 because such information is not available to the Company.
Undeveloped reserves are those reserves where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. Undeveloped reserves may be booked to projects that have both proved (high certainty) and probable (less certain, but expected to be recovered) reserves, and some projects that have only probable reserves. The following table presents the first attributed undeveloped reserve additions for the past four years.
46
Proved Undeveloped Reserves(1)
| | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | Natural Gas
Liquids
(mmbbls) | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
Prior Years | | 58.4 | | 1.2 | | 9.2 | | 1,783.1 | | 368.1 | | 29.2 | |
2013 | | 2.6 | | — | | 1.3 | | 533.6 | | 41.0 | | 19.8 | |
2014 | | 4.5 | | 0.1 | | 3.0 | | 220.9 | | 29.8 | | 6.3 | |
2015(2) | | — | | 0.4 | | 0.9 | | 204.8 | | 20.4 | | 7.7 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | |
Prior Years | | — | | — | | — | | — | | — | | — | |
2013 | | 2.2 | | — | | — | | — | | 1.4 | | — | |
2014 | | 0.8 | | — | | — | | — | | — | | — | |
2015(3) | | — | | — | | — | | — | | — | | — | |
TOTAL ROGCI | | | | | | | | | | | | | |
2015(4) | | — | | 0.4 | | 0.9 | | 204.8 | | 20.4 | | 7.7 | |
Probable Undeveloped Reserves(1)
| | Light Oil
(mmbbls) | | Heavy Oil
(mmbbls) | | Tight Oil
(mmbbls) | | Shale Gas
(bcf) | | Conventional
Natural Gas
(bcf) | | Natural Gas
Liquids
(mmbbls) | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
Prior Years | | 74.5 | | 0.5 | | 1.6 | | 877.3 | | 194.6 | | 11.4 | |
2013 | | 15.7 | | — | | 0.6 | | 289.4 | | 130.0 | | 10.0 | |
2014 | | 38.8 | | 0.3 | | 0.4 | | 186.8 | | 17.7 | | 2.9 | |
2015(2) | | 1.1 | | 0.2 | | 0.1 | | 176.4 | | 96.0 | | 2.8 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | |
Prior Years | | — | | — | | — | | — | | — | | — | |
2013 | | 0.2 | | — | | — | | — | | — | | — | |
2014 | | 1.0 | | — | | — | | — | | 4.6 | | — | |
2015(3) | | — | | — | | — | | — | | — | | — | |
TOTAL ROGCI | | | | | | | | | | | | | |
2015(4) | | 1.1 | | 0.2 | | 0.1 | | 176.4 | | 96.0 | | 2.8 | |
(1) First attributed includes only new additions during the year and does not include revisions to previous undeveloped reserves.
(2) Does not include the Company’s investments in TSEUK or Equion, shown separately under “Equity Investments” in this table.
(3) The Company’s investments in TSEUK and Equion were accounted for based on the equity method of accounting commencing January 1, 2013. Data prior to 2013 is included under “Consolidated Entities” where applicable.
(4) Includes the Company’s equity investments in TSEUK and Equion.
As at December 31, 2015, the Company’s proved undeveloped reserves were 213 mmboe and proved plus probable undeveloped reserves were 493 mmboe. These values represent 25% and 38% of the Company’s total proved and total proved plus probable reserves respectively. The Company plans to develop 93% of proved and 91% of proved plus probable reserves within the next five years. As of December 31, 2015 the only material proved plus probable undeveloped reserves that were five years or older were in Indonesia (32 mmboe), and the UK (10 mmboe). The Indonesian undeveloped gas reserves will be developed as needed in the next five years to meet gas deliverability requirements for existing gas contracts. The UK undeveloped oil reserves are located in offshore projects that are underway and where significant capital has already been spent.
47
Future Development Costs(1)
The following tables set forth the development costs ($ millions) deducted in the estimation of future net revenue.
| | Canada | | United States | | Southeast Asia | |
Year | | Proved | | Proved Plus Probable | | Proved | | Proved Plus Probable | | Proved | | Proved Plus Probable | |
2016 | | 54.3 | | 60.1 | | 228.9 | | 285.2 | | 95.0 | | 198.1 | |
2017 | | 43.3 | | 49.8 | | 144.4 | | 232.8 | | 60.5 | | 513.1 | |
2018 | | 13.0 | | 50.4 | | 200.1 | | 304.1 | | 43.2 | | 478.7 | |
2019 | | 33.7 | | 59.0 | | 161.6 | | 225.0 | | 10.8 | | 265.1 | |
2020 | | 72.2 | | 98.4 | | 98.1 | | 130.1 | | 8.9 | | 117.5 | |
Remainder | | 295.8 | | 292.3 | | 85.6 | | 89.2 | | 83.1 | | 268.6 | |
Total: Undiscounted | | 512.3 | | 610.0 | | 918.7 | | 1,266.4 | | 301.5 | | 1,841.1 | |
| | Latin America | | Other | |
Year | | Proved | | Proved Plus
Probable | | Proved | | Proved Plus
Probable | |
2016 | | 24.7 | | 30.8 | | 2.9 | | 2.9 | |
2017 | | 3.3 | | 32.2 | | — | | 13.4 | |
2018 | | — | | 33.8 | | — | | 20.4 | |
2019 | | — | | — | | — | | 2.2 | |
2020 | | — | | — | | — | | 2.0 | |
Remainder | | — | | — | | — | | 10.3 | |
Total: Undiscounted | | 28.0 | | 96.8 | | 2.9 | | 51.2 | |
EQUITY INVESTMENTS
| | TSEUK | | Equion | |
Year | | Proved | | Proved Plus
Probable | | Proved | | Proved Plus
Probable | |
2016 | | 234.7 | | 234.7 | | 11.1 | | 11.1 | |
2017 | | 80.1 | | 80.1 | | 0.9 | | 0.9 | |
2018 | | 68.8 | | 68.8 | | 0.7 | | 0.7 | |
2019 | | 62.4 | | 62.4 | | 0.6 | | 0.6 | |
2020 | | 71.1 | | 71.1 | | 0.1 | | 0.1 | |
Remainder | | 88.5 | | 163.0 | | — | | — | |
Total: Undiscounted | | 605.6 | | 680.1 | | 13.4 | | 13.4 | |
(1) Includes development and maintenance costs.
The Company expects to fund future development from internally generated cash flow, existing cash balances, debt financing and the proceeds of farm-out arrangements. The only costs of funding future development is the interest associated with debt financing. The interest associated with debt financing is not included in the reserves and future revenue estimates and would reduce reserves and future net revenue to some degree depending on the funding source utilized. The Company does not expect that interest or other funding costs would make the development of any property uneconomic.
48
Pricing Assumptions
The pricing assumptions used in the preparation of the estimates of reserves and related future net revenue are set forth below. By 2025, oil prices are assuming a long-term estimate of $75.20/bbl Brent crude oil in real 2016 dollars, and, by 2022, gas prices are assuming a long term estimate of $4.28/mmbtu NYMEX in real 2016 dollars.
| | Oil(1) | | Natural Gas | | Natural
Gas
Liquids | | | | | | | |
Year | | USA
WTI
Cushing
Oklahoma
(US$/bbl) | | Canada
Western
Canadian
Select
Hardisty
Heavy
(C$/bbl) | | UK
Dated
Brent(4)
(US$/bbl) | | USA(2)
Henry Hub
(US$/
mmbtu) | | Canada(3)
AECO-C
(C$/gj) | | UK
IPE
M-1(4)
(P/therm) | | Canada
Edmonton
Propane
(C$/bbl) | | Inflation
Rates
%/year | | Exchange
Rate
(US$ equal)
C$1.00 | | Exchange
Rate
(US$ equal)
UK £1.00 | |
2016 | | 40.00 | | 32.00 | | 40.00 | | 2.60 | | 2.58 | | 25.66 | | 11.34 | | 2.1% | | 0.75 | | 1.52 | |
2017 | | 55.00 | | 44.00 | | 55.00 | | 3.20 | | 3.12 | | 36.73 | | 17.00 | | 2.0% | | 0.80 | | 1.47 | |
2018 | | 65.00 | | 52.00 | | 65.00 | | 3.70 | | 3.71 | | 43.54 | | 21.00 | | 1.9% | | 0.80 | | 1.47 | |
2019 | | 75.00 | | 60.00 | | 75.00 | | 4.20 | | 4.25 | | 45.95 | | 24.94 | | 1.8% | | 0.81 | | 1.48 | |
2020 | | 85.00 | | 68.00 | | 85.00 | | 4.80 | | 4.95 | | 50.00 | | 38.23 | | 1.9% | | 0.81 | | 1.48 | |
2021 | | 86.70 | | 69.36 | | 86.70 | | 4.90 | | 5.15 | | 51.68 | | 39.08 | | 2.0% | | 0.82 | | 1.49 | |
Thereafter | | (+2 %/yr5 | | +2 %/yr5 | | +2 %/yr5 | | +2 %/yr5 | | +2 %/yr5 | | +2 %/yr5) | | +2 %/yr | | | | | | | |
(1) Asian gas prices are generally linked to oil, except for certain contracts which contain fixed prices.
(2) US shale gas price is based on Henry Hub.
(3) Canadian shale gas price is based on AECO.
(4) Oil prices in UK and Other are generally derived from Dated Brent with quality and transportation differentials.
(5) Rates are approximate.
Weighted average historical prices for the year ended December 31, 2015, with respect to the Company’s consolidated entities and equity investments were $51.12/bbl for light oil, $37.61/bbl for tight oil, $35.56/bbl for heavy oil, $2.23/mcf for shale gas, $4.65/mcf for natural gas and $21.35/bbl for natural gas liquids.
49
Definitions
Conventional Natural Gas is a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in light oil in reservoirs but are gaseous at atmospheric conditions, but which excludes shale. Natural gas may contain sulphur or other non-hydrocarbon compounds.
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.
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.
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.
Gross Reserves are the Company’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company.
Heavy Oil is oil that qualifies for royalties specific to heavy oil, in a jurisdiction that has a royalty regime specific to heavy oil; or is oil with a density between 10 to 22.3 degrees API (as that term is defined by the American Petroleum Institute), in a jurisdiction that has no royalty regime specific to heavy oil.
Light Oil is a mixture consisting mainly of pentanes and heavier hydrocarbons that exist in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Light Oil may contain small amounts of sulphur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.
Natural Gas Liquids are those hydrocarbon components that can be recovered from natural gas as liquids, including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.
Net Reserves are the Company’s working interest (operating or non-operating) share after deduction of royalty obligations, plus the Company’s royalty interests in reserves.
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.
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.
Shale Gas is derived from shales and similar low permeability formations and is typically developed with horizontal drilling and multi-stage fracture stimulations. It is a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in shale oil in reservoirs but are gaseous at atmospheric conditions. Shale gas may contain sulphur or other non-hydrocarbon compounds. In this Annual Information Form, reserves reported under the Shale Gas product type include reserves in the Marcellus, Montney, Eagle Ford and Duvernay plays.
Tight Oil is derived from shale and is a mixture consisting mainly of pentanes and heavier hydrocarbons that exist in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Tight Oil may contain small amounts of sulphur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.
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, possible) to which they are assigned.
50
Wells
The following table sets forth the number of the Company’s producing and non-producing wells as at December 31, 2015.
| | Oil Wells | | Natural Gas Wells | |
| | Producing | | Non-Producing(1) | | Producing | | Non-Producing(1) | |
Year ended December 31, 2015 | | Gross(2) | | Net(2) | | Gross(2) | | Net(2) | | Gross(2) | | Net(2) | | Gross(2) | | Net(2) | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | | | | | |
Alberta | | 1,163.0 | | 936.7 | | 309.0 | | 198.9 | | 1,551.0 | | 842.1 | | 296.0 | | 141.5 | |
British Columbia | | — | | — | | 4.0 | | 0.2 | | 41.0 | | 13.0 | | 26.0 | | 13.4 | |
Saskatchewan | | 23.0 | | 22.0 | | 33.0 | | 27.4 | | 8.0 | | 5.2 | | 36.0 | | 20.0 | |
Quebec | | — | | — | | — | | — | | — | | — | | 11.0 | | 8.6 | |
Northwest Territories | | — | | — | | — | | — | | 3.0 | | — | | 9.0 | | — | |
Yukon | | — | | — | | — | | — | | — | | — | | 1.0 | | — | |
Total Canada | | 1,186.0 | | 958.7 | | 346.0 | | 226.5 | | 1,603.0 | | 860.3 | | 379.0 | | 183.5 | |
Texas | | 174.0 | | 84.1 | | 21.0 | | 8.0 | | 499.0 | | 196.2 | | 40.0 | | 12.3 | |
New York | | — | | — | | — | | — | | 74.0 | | 64.2 | | 28.0 | | 17.6 | |
Pennsylvania | | — | | — | | — | | — | | 498.0 | | 411.7 | | 64.0 | | 37.0 | |
Total United States | | 174.0 | | 84.1 | | 21.0 | | 8.0 | | 1,071.0 | | 672.1 | | 132.0 | | 66.9 | |
Indonesia | | 89.0 | | 35.3 | | 152.0 | | 58.0 | | 51.0 | | 13.6 | | 26.0 | | 7.8 | |
Malaysia | | 87.0 | | 39.5 | | 12.0 | | 5.3 | | 36.0 | | 14.9 | | 10.0 | | 4.1 | |
Australia/Timor-Leste | | 4.0 | | 1.5 | | 8.0 | | 2.7 | | — | | — | | — | | — | |
Vietnam | | 35.0 | | 3.9 | | 3.0 | | — | | — | | — | | — | | — | |
Papua New Guinea | | — | | — | | — | | — | | — | | — | | 14.0 | | 6.0 | |
Colombia(3) | | 17.0 | | 8.0 | | 12.0 | | 5.3 | | — | | — | | — | | — | |
Algeria | | 86.0 | | 9.1 | | 38.0 | | 4.8 | | — | | — | | 2.0 | | 0.2 | |
Kurdistan Region of Iraq | | — | | — | | 3.0 | | 0.7 | | — | | — | | 2.0 | | 0.5 | |
Total Other | | 318.0 | | 97.3 | | 228.0 | | 76.8 | | 87.0 | | 28.5 | | 54.0 | | 18.6 | |
TOTAL CONSOLIDATED ENTITIES | | 1,678.0 | | 1,140.1 | | 595.0 | | 311.3 | | 2,761.0 | | 1,560.9 | | 565.0 | | 269.0 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | | | | | |
TSEUK | | 159.0 | | 43.0 | | 220.0 | | 75.9 | | 1.0 | | 0.1 | | 2.0 | | 0.5 | |
Equión | | 53.0 | | 8.4 | | 25.0 | | 2.9 | | — | | — | | 1.0 | | 0.2 | |
TOTAL EQUITY INVESTMENTS | | 212.0 | | 51.4 | | 245.0 | | 78.8 | | 1.0 | | 0.1 | | 3.0 | | 0.8 | |
TOTAL ROGCI(4) | | 1,890.0 | | 1,191.4 | | 840.0 | | 390.1 | | 2,762.0 | | 1,561.0 | | 568.0 | | 269.8 | |
(1) Non producing includes those wells that were not producing at year end but are capable of producing.
(2) “Gross wells” means the total number of wells in which the Company has interests. “Net wells” means the number of wells obtained by aggregating the Company’s working interest in each of its gross wells.
(3) Colombia does not include wells owned by Equion, shown separately under “Equity Investments” in this table.
(4) Total Consolidated Entities plus Total Equity Investments.
For further information, please refer to the “Description of the Business” section of this Annual Information Form.
51
Properties with no Attributed Reserves
The following table sets out the Company’s land holdings with no attributed reserves at December 31, 2015:
| | Properties with no
Attributed Reserves
(thousand acres)(1) | |
| | Gross | | Net | |
CONSOLIDATED ENTITIES | | | | | |
Canada(2) | | 6,633.2 | | 4,135.9 | |
United States(2) | | 335.0 | | 281.6 | |
North Sea(3) | | — | | — | |
Southeast Asia(4) | | 25,232.6 | | 15,726.5 | |
Latin America(5) | | 8,845.9 | | 4,246.2 | |
Other(6) | | 310.0 | | 136.3 | |
TOTAL CONSOLIDATED ENTITIES | | 41,356.8 | | 24,526.5 | |
EQUITY INVESTMENTS | | | | | |
TSEUK | | 477.7 | | 141.6 | |
Equión | | — | | — | |
TOTAL EQUITY INVESTMENTS | | | | | |
TOTAL COMPANY(7) | | 41,834.5 | | 24,668.1 | |
(1) Where the Company holds interests in different formations under the same surface area but pursuant to separate leases, the acreage for each lease is included in total gross and net acreage.
(2) There are no work commitments for any of the lands.
(3) North Sea does not include the Company’s investment in TSEUK, shown separately under “Equity Investments” in this table. Substantially all of the assets and liabilities of the Company’s Norwegian operations were sold, as of September 1, 2015.
(4) Southeast Asia includes Indonesia, Vietnam, Malaysia, Australia/Timor Leste and Papua New Guinea as at December 31, 2015.
(5) Latin America does not include the Company’s investment in Equion, shown separately under “Equity Investments” in this table.
(6) Other includes the Kurdistan Region of Iraq and Algeria.
(7) Total Consolidated Entities plus Total Equity Investments.
Work commitments, categorized as seismic acquisition, geophysical studies or well commitments (land and/or licence commitments), exist in all of the Company’s geographic areas except Canada and the United States where there are no comparable work commitments for any of the lands held. In Canada and the United States, the Company’s ultimate ability to retain land typically requires drilling activity and/or proof of productivity. In other regions in which the Company operates, the result of not fulfilling a land or licence commitment could result in the loss of a title document or imposition of a penalty. The Company’s total work commitments with respect to its consolidated entities for the next two years are estimated to be $568.8 million.
The estimated net acres of properties with no attributed reserves (thousand acres) that are expected to expire in 2016 are as follows: Canada - 35.3, United States - 31.0 and Latin America - 296.5.
Forward Contracts
Future commitments to buy, sell, exchange, process and transport oil or gas of the Company are described under note 22 entitled “Contingencies and Commitments” in the audited Consolidated Financial Statements of the Company for the year ended December 31, 2015, which is incorporated herein by reference.
52
Costs Incurred
The following table summarizes the capital expenditures made by the Company on oil and natural gas properties for the year ended December 31, 2015.
| | Property Acquisition Costs
($ Millions) | | Exploration | | Development | |
| | Proved
Properties | | Unproved
Properties | | Costs
($ Millions) | | Costs
($ Millions) | |
CONSOLIDATED ENTITIES | | | | | | | | | |
Canada | | — | | 3 | | 152 | | 210 | |
United States | | — | | 41 | | 13 | | 422 | |
UK | | — | | — | | 16 | | | |
Norway | | — | | — | | 20 | | 55 | |
Southeast Asia | | — | | 8 | | 140 | | 151 | |
Other(1) | | — | | | | 49 | | 33 | |
TOTAL CONSOLIDATED ENTITIES | | — | | 52 | | 390 | | 871 | |
EQUITY INVESTMENTS | | | | | | | | | |
TSEUK | | 2 | | — | | 14 | | 324 | |
Equión | | | | | | | | 42 | |
TOTAL EQUITY INVESTMENTS | | 2 | | — | | 14 | | 366 | |
TOTAL ROGCI | | 2 | | 52 | | 404 | | 1237 | |
(1) “Other” includes Algeria, Colombia and the Kurdistan Region of Iraq.
Exploration and Development Activities
For a description of the Company’s most important current and likely exploration and development activities, please refer to the “Description of the Business” section of this Annual Information Form. The following tables set forth the number of wells completed in the year ended December 31, 2015:
| | Exploratory Wells | | Development Wells | | Total | |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | |
Oil | | — | | — | | 15.0 | | 15.0 | | 15.0 | | 15.0 | |
Gas | | 8.0 | | 8.0 | | 41.0 | | 29.0 | | 49.0 | | 37.0 | |
Service | | — | | — | | 5.0 | | 5.0 | | 5.0 | | 5.0 | |
Stratigraphic Test | | — | | — | | 1.0 | | 1.0 | | 1.0 | | 1.0 | |
Dry | | — | | — | | — | | — | | — | | — | |
Total | | 8.0 | | 8.0 | | 62.0 | | 50.0 | | 70.0 | | 58.0 | |
United States | | | | | | | | | | | | | |
Oil | | — | | — | | 10.0 | | 5.0 | | 10.0 | | 5.0 | |
Gas | | — | | — | | 160.0 | | 57.7 | | 160.0 | | 57.7 | |
Service | | — | | — | | — | | — | | — | | — | |
Stratigraphic Test | | — | | — | | — | | — | | — | | — | |
Dry | | — | | — | | — | | — | | — | | — | |
Total | | — | | — | | 170.0 | | 62.7 | | 170.0 | | 62.7 | |
53
| | Exploratory Wells | | Development Wells | | Total | |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | |
North Sea(1) | | | | | | | | | | | | | |
Oil | | — | | — | | 3.0 | | 0.8 | | 3.0 | | 0.8 | |
Gas | | — | | — | | — | | — | | — | | — | |
Service | | — | | — | | 1.0 | | 0.1 | | 1.0 | | 0.1 | |
Stratigraphic Test | | — | | — | | — | | — | | — | | — | |
Dry | | 2.0 | | 0.9 | | — | | — | | 2.0 | | 0.9 | |
Total | | 2.0 | | 0.9 | | 4.0 | | 0.9 | | 6.0 | | 1.7 | |
Southeast Asia(2) | | | | | | | | | | | | | |
Oil | | 2.0 | | — | | 7.0 | | 0.3 | | 9.0 | | 0.3 | |
Gas | | 2.0 | | 1.0 | | 4.0 | | 1.5 | | 6.0 | | 2.5 | |
Service | | — | | — | | 1.0 | | 0.4 | | 1.0 | | 0.4 | |
Stratigraphic Test | | — | | — | | — | | — | | — | | — | |
Dry | | 1.0 | | 0.7 | | — | | — | | 1.0 | | 0.7 | |
Total | | 5.0 | | 1.7 | | 12.0 | | 2.2 | | 17.0 | | 3.9 | |
Latin America(3) | | | | | | | | | | | | | |
Oil | | 2.0 | | 0.9 | | — | | — | | 2.0 | | 0.9 | |
Gas | | — | | — | | — | | — | | — | | — | |
Service | | — | | — | | — | | — | | — | | — | |
Stratigraphic Test | | — | | — | | — | | — | | — | | — | |
Dry | | — | | — | | — | | — | | — | | — | |
Total | | 2.0 | | 0.9 | | — | | — | | 2.0 | | 0.9 | |
Other(4) | | | | | | | | | | | | | |
Oil | | — | | — | | — | | — | | — | | — | |
Gas | | — | | — | | 1.0 | | 0.1 | | 1.0 | | 0.1 | |
Service | | — | | — | | — | | — | | — | | — | |
Stratigraphic Test | | — | | — | | — | | — | | — | | — | |
Dry | | — | | — | | — | | — | | — | | — | |
Total | | — | | — | | 1.0 | | 0.1 | | 1.0 | | 0.1 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | |
TSEUK | | | | | | | | | | | | | |
Oil | | — | | — | | 1.0 | | 0.6 | | 1.0 | | 0.6 | |
Gas | | — | | — | | 1.0 | | 0.6 | | 1.0 | | 0.6 | |
Service | | — | | — | | — | | — | | — | | — | |
Stratigraphic Test | | — | | — | | — | | — | | — | | — | |
Dry | | — | | — | | — | | — | | — | | — | |
Total | | — | | — | | 2.0 | | 1.2 | | 2.0 | | 1.2 | |
Equión | | | | | | | | | | | | | |
Oil | | — | | — | | 5.0 | | 1.1 | | 5.0 | | 1.1 | |
Gas | | — | | — | | — | | — | | — | | — | |
Service | | — | | — | | — | | — | | — | | — | |
Stratigraphic Test | | — | | — | | — | | — | | — | | — | |
Dry | | — | | — | | — | | — | | — | | — | |
Total | | — | | — | | 5.0 | | 1.1 | | 5.0 | | 1.1 | |
(1) North Sea does not include the Company’s investment in TSEUK, shown separately under “Equity Investments” in this table. Substantially all of the assets and liabilities of the Company’s Norwegian operations were sold as of September 1, 2015.
(2) Southeast Asia includes Indonesia, Malaysia, Vietnam, Australia/Timor-Leste and Papua New Guinea.
(3) Latin America does not include the Company’s investment in Equion, shown separately under “Equity Investments” in this table.
(4) Other refers to the Kurdistan Region of Iraq and Algeria.
54
Production Estimates
The following table sets forth the volume of working interest production, before royalties, estimated for 2016, which is reflected in the estimate of future net revenue disclosed in the tables of reserves information in respect of gross proved and probable reserves:
| | Product | |
| | Light Oil
(mbbls) | | Heavy Oil
(mbbls) | | Tight Oil
(mbbls) | | Shale Gas
(mmscf) | | Conventional
Natural Gas
(mmscf) | | Natural Gas
Liquids
(mbbls) | |
CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | |
Total Proved | | 445.3 | | 2,720.3 | | — | | 4,810.6 | | 63,015.0 | | 3,808.0 | |
Total Probable | | 43.9 | | 220.4 | | — | | 471.6 | | 4,554.0 | | 379.2 | |
Total Proved Plus Probable | | 489.2 | | 2,940.7 | | — | | 5,282.1 | | 67,569.0 | | 4,187.2 | |
United States | | | | | | | | | | | | | |
Total Proved | | — | | — | | 906.3 | | 184,266.7 | | 2,827.9 | | 3,936.2 | |
Total Probable | | — | | — | | 3.6 | | 7,388.0 | | 571.6 | | 44.7 | |
Total Proved Plus Probable | | — | | — | | 909.9 | | 191,654.7 | | 3,399.5 | | 3,980.9 | |
Southeast Asia(1) | | | | | | | | | | | | | |
Total Proved | | 9,713.7 | | — | | — | | — | | 174,690.4 | | — | |
Total Probable | | 710.6 | | — | | — | | — | | 656.7 | | — | |
Total Proved Plus Probable | | 10,424.3 | | — | | — | | — | | 175,347.2 | | — | |
Latin America(2) | | | | | | | | | | | | | |
Total Proved | | — | | 1,841.4 | | — | | — | | — | | — | |
Total Probable | | — | | 136.1 | | — | | — | | — | | — | |
Total Proved Plus Probable | | — | | 1,977.5 | | — | | — | | — | | — | |
Other(3) | | | | | | | | | | | | | |
Total Proved | | 3,170.5 | | — | | — | | — | | — | | 196.1 | |
Total Probable | | 609.6 | | — | | — | | — | | — | | 29.7 | |
Total Proved Plus Probable | | 3,780.1 | | — | | — | | — | | — | | 225.8 | |
TOTAL CONSOLIDATED ENTITIES | | | | | | | | | | | | | |
Total Proved | | 13,329.4 | | 4,561.7 | | 906.3 | | 189,077.3 | | 240,533.3 | | 7,940.3 | |
Total Probable | | 1,364.2 | | 356.5 | | 3.6 | | 7,859.6 | | 5,782.4 | | 453.6 | |
Total Proved Plus Probable | | 14,693.6 | | 4,918.2 | | 909.9 | | 196,936.9 | | 246,315.7 | | 8,393.9 | |
EQUITY INVESTMENTS | | | | | | | | | | | | | |
TSEUK | | | | | | | | | | | | | |
Total Proved | | 4,144.1 | | — | | — | | — | | 242.2 | | 11.8 | |
Total Probable | | 1,171.7 | | — | | — | | — | | 168.8 | | 2.9 | |
Total Proved Plus Probable | | 5,315.8 | | — | | — | | — | | 411.0 | | 14.8 | |
Equion | | | | | | | | | | | | | |
Total Proved | | 3,477.4 | | — | | — | | — | | 12,642.1 | | 435.5 | |
Total Probable | | 728.4 | | — | | — | | — | | 834.5 | | 41.6 | |
Total Proved Plus Probable | | 4,205.8 | | — | | — | | — | | 13,476.6 | | 477.1 | |
TOTAL EQUITY INVESTMENTS | | | | | | | | | | | | | |
Total Proved | | 7,621.5 | | — | | — | | — | | 12,884.3 | | 447.3 | |
Total Probable | | 1,900.1 | | — | | — | | — | | 1,003.4 | | 44.5 | |
Total Proved Plus Probable | | 9,521.6 | | — | | — | | — | | 13,887.7 | | 491.8 | |
TOTAL ROGCI(4) | | | | | | | | | | | | | |
Total Proved | | 20,951.0 | | 4,561.7 | | 906.3 | | 189,077.3 | | 253,417.7 | | 8,387.6 | |
Total Probable | | 3,264.3 | | 356.5 | | 3.6 | | 7,859.6 | | 6,785.7 | | 498.1 | |
Total Proved Plus Probable | | 24,215.3 | | 4,918.2 | | 909.9 | | 196,936.9 | | 260,203.4 | | 8,885.7 | |
(1) Southeast Asia includes production in Indonesia, Malaysia, Vietnam and Australia/Timor-Leste.
(2) Latin America does not include the Company’s investment in Equion, shown separately under “Equity Investments” in this table.
(3) Other refers to Algeria.
(4) Total Consolidated Entities plus Total Equity Investments.
55
Production History
Average Daily Production and Netback Information
The following table sets forth certain information in respect of production, product prices received, royalties, production costs and netbacks received by the Company for each quarter in 2015 and the total for 2015:
| | Quarter Ended | | Total Year | |
| | 31-Mar | | 30-Jun | | 30-Sep | | 31-Dec | | 2015 | |
CONSOLIDATED ENTITIES | | | | | | | | | | | |
Canada | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 721 | | 641 | | 561 | | 541 | | 616 | |
Tight Oil (bbl/d) | | — | | — | | — | | — | | — | |
Shale Gas (mmcf/d) | | 15 | | 13 | | 11 | | 12 | | 13 | |
Natural Gas (mmcf/d) | | 207 | | 195 | | 189 | | 218 | | 202 | |
Natural Gas Liquids (bbl/d) | | 13,318 | | 10,198 | | 10,393 | | 11,899 | | 11,445 | |
Heavy Oil (bbl/d) | | 10,051 | | 10,275 | | 10,246 | | 10,192 | | 10,190 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 43.97 | | 56.32 | | 44.76 | | 38.35 | | 46.06 | |
Tight Oil ($/bbl) | | — | | — | | — | | — | | — | |
Shale Gas ($/mcf) | | 2.88 | | 2.71 | | 2.48 | | 2.16 | | 2.57 | |
Natural Gas ($/mcf) | | 2.63 | | 2.32 | | 2.37 | | 1.97 | | 2.32 | |
Natural Gas Liquids ($/bbl) | | 19.87 | | 21.74 | | 17.05 | | 17.64 | | 19.05 | |
Heavy Oil ($/bbl) | | 33.46 | | 46.34 | | 33.73 | | 28.63 | | 35.56 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 2.94 | | 5.92 | | 4.36 | | 6.73 | | 4.87 | |
Tight Oil ($/bbl) | | — | | — | | — | | — | | — | |
Shale Gas ($/mcf) | | 0.13 | | 0.09 | | (0.38 | ) | 0.04 | | (0.02 | ) |
Natural Gas ($/mcf) | | 0.07 | | 0.08 | | 0.16 | | 0.11 | | 0.10 | |
Natural Gas Liquids ($/bbl) | | 0.55 | | 0.16 | | (1.80 | ) | 1.40 | | 0.15 | |
Heavy Oil ($/bbl) | | 3.00 | | 2.78 | | 2.84 | | 1.89 | | 2.63 | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 39.15 | | 33.30 | | 6.66 | | 25.96 | | 27.21 | |
Tight Oil ($/bbl) | | — | | — | | — | | — | | — | |
Shale Gas ($/mcf) | | 3.03 | | 4.01 | | 3.65 | | 2.79 | | 3.35 | |
Natural Gas ($/mcf) | | 1.59 | | 1.71 | | 1.73 | | 1.45 | | 1.62 | |
Natural Gas Liquids ($/bbl) | | 11.70 | | 4.37 | | 7.50 | | 7.04 | | 7.89 | |
Heavy Oil ($/bbl) | | 15.72 | | 7.98 | | 11.60 | | 8.39 | | 10.89 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 1.88 | | 17.10 | | 33.74 | | 5.66 | | 13.98 | |
Tight Oil ($/bbl) | | — | | — | | — | | — | | — | |
Shale Gas ($/mcf) | | (0.28 | ) | (1.39 | ) | (0.79 | ) | (0.67 | ) | (0.76 | ) |
Natural Gas ($/mcf) | | 0.97 | | 0.53 | | 0.48 | | 0.41 | | 0.60 | |
Natural Gas Liquids ($/bbl) | | 7.62 | | 17.21 | | 11.35 | | 9.20 | | 11.01 | |
Heavy Oil ($/bbl) | | 14.74 | | 35.58 | | 19.29 | | 18.35 | | 22.04 | |
56
| | Quarter Ended | | Total Year | |
| | 31-Mar | | 30-Jun | | 30-Sep | | 31-Dec | | 2015 | |
United States | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | — | | — | | — | | — | | — | |
Tight Oil (bbl/d) | | 12,228 | | 11,257 | | 10,756 | | 11,656 | | 11,472 | |
Shale Gas (mmcf/d) | | 563 | | 557 | | 575 | | 577 | | 568 | |
Natural Gas (mmcf/d) | | 14 | | 15 | | 14 | | 13 | | 14 | |
Natural Gas Liquids (bbl/d) | | 7,786 | | 8,941 | | 7,920 | | 9,203 | | 8,465 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | — | | — | | — | | — | | — | |
Tight Oil ($/bbl) | | 38.54 | | 35.95 | | 40.78 | | 35.31 | | 37.61 | |
Shale Gas ($/mcf) | | 2.60 | | 2.19 | | 2.18 | | 1.94 | | 2.22 | |
Natural Gas ($/mcf) | | 1.81 | | 1.31 | | 1.18 | | 1.12 | | 1.36 | |
Natural Gas Liquids ($/bbl) | | 16.07 | | 17.44 | | 15.51 | | 16.17 | | 16.33 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | — | | — | | — | | — | | — | |
Tight Oil ($/bbl) | | 6.07 | | 11.73 | | 11.07 | | 9.25 | | 9.45 | |
Shale Gas ($/mcf) | | 0.44 | | 0.37 | | 0.38 | | 0.27 | | 0.36 | |
Natural Gas ($/mcf) | | 0.26 | | 0.19 | | 0.17 | | 0.16 | | 0.19 | |
Natural Gas Liquids ($/bbl) | | 3.66 | | 3.52 | | 4.71 | | 4.11 | | 3.99 | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | — | | — | | — | | — | | — | |
Tight Oil ($/bbl) | | 13.01 | | 1.25 | | 7.96 | | 4.78 | | 6.83 | |
Shale Gas ($/mcf) | | 1.62 | | 1.22 | | 1.14 | | 1.28 | | 1.31 | |
Natural Gas ($/mcf) | | 2.12 | | 1.39 | | 0.89 | | 1.45 | | 1.46 | |
Natural Gas Liquids ($/bbl) | | 12.44 | | (1.66 | ) | 2.61 | | 3.08 | | 3.84 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | — | | — | | — | | — | | — | |
Tight Oil ($/bbl) | | 19.46 | | 22.97 | | 21.75 | | 21.28 | | 21.33 | |
Shale Gas ($/mcf) | | 0.54 | | 0.60 | | 0.66 | | 0.39 | | 0.55 | |
Natural Gas ($/mcf) | | (0.57 | ) | (0.27 | ) | 0.12 | | (0.49 | ) | (0.29 | ) |
Natural Gas Liquids ($/bbl) | | (0.03 | ) | 15.58 | | 8.19 | | 8.98 | | 8.50 | |
Norway | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 11,896 | | 10,847 | | 8,813 | | — | | 7,859 | |
Natural Gas (mmcf/d) | | 17 | | 21 | | 18 | | — | | 14 | |
Natural Gas Liquids (bbl/d) | | 1,431 | | 1,708 | | 1,170 | | — | | 1,074 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 52.23 | | 67.02 | | 39.01 | | — | | 53.58 | |
Natural Gas ($/mcf) | | 7.57 | | 6.74 | | 6.90 | | — | | 7.04 | |
Natural Gas Liquids ($/bbl) | | 35.08 | | 31.14 | | 17.73 | | — | | 28.75 | |
57
| | Quarter Ended | | Total Year | |
| | 31-Mar | | 30-Jun | | 30-Sep | | 31-Dec | | 2015 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | — | | — | | — | | — | | — | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | — | | — | | — | | — | | — | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 49.49 | | 53.88 | | 40.29 | | — | | 48.60 | |
Natural Gas ($/mcf) | | 1.70 | | 1.68 | | 1.67 | | — | | 1.71 | |
Natural Gas Liquids ($/bbl)(1) | | 9.55 | | 9.43 | | 9.38 | | — | | 9.60 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 2.74 | | 13.14 | | (1.28 | ) | — | | 4.98 | |
Natural Gas ($/mcf) | | 5.87 | | 5.06 | | 5.23 | | — | | 5.33 | |
Natural Gas Liquids ($/bbl) | | 25.53 | | 21.71 | | 8.35 | | — | | 19.15 | |
Southeast Asia | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 35,080 | | 33,836 | | 29,089 | | 29,731 | | 31,911 | |
Natural Gas (mmcf/d) | | 482 | | 496 | | 464 | | 492 | | 483 | |
Natural Gas Liquids (bbl/d) | | 3,882 | | 3,834 | | 3,890 | | 3,762 | | 3,842 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 54.37 | | 65.38 | | 45.07 | | 41.23 | | 52.06 | |
Natural Gas ($/mcf) | | 6.20 | | 6.08 | | 5.61 | | 4.99 | | 5.72 | |
Natural Gas Liquids ($/bbl) | | 41.47 | | 41.55 | | 39.80 | | 37.20 | | 40.01 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 16.28 | | 19.96 | | 14.20 | | 13.55 | | 16.14 | |
Natural Gas ($/mcf) | | 1.74 | | 1.71 | | 1.61 | | 1.41 | | 1.62 | |
Natural Gas Liquids ($/bbl) | | 19.53 | | 29.42 | | 16.52 | | 16.82 | | 20.55 | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 20.08 | | 16.78 | | 22.96 | | 20.72 | | 20.01 | |
Natural Gas ($/mcf) | | 1.20 | | 0.93 | | 0.99 | | 1.12 | | 1.07 | |
Natural Gas Liquids ($/bbl)(1) | | 6.74 | | 5.22 | | 5.56 | | 6.29 | | 6.01 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 18.01 | | 28.64 | | 7.91 | | 6.96 | | 15.91 | |
Natural Gas ($/mcf) | | 3.26 | | 3.44 | | 3.01 | | 2.46 | | 3.03 | |
Natural Gas Liquids ($/bbl) | | 15.21 | | 6.91 | | 17.72 | | 14.09 | | 13.45 | |
Latin America(3) | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 3,252 | | 3,765 | | 3,087 | | 1,533 | | 2,905 | |
Natural Gas (mmcf/d) | | — | | — | | — | | — | | — | |
Natural Gas Liquids (bbl/d) | | — | | — | | — | | — | | — | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 53.58 | | 52.11 | | 39.68 | | 22.73 | | 45.28 | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | — | | — | | — | | — | | — | |
58
| | Quarter Ended | | Total Year | |
| | 31-Mar | | 30-Jun | | 30-Sep | | 31-Dec | | 2015 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 11.71 | | 11.59 | | 8.78 | | 4.98 | | 9.99 | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | — | | — | | — | | — | | — | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 53.11 | | 51.74 | | 49.03 | | 54.18 | | 51.71 | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | — | | — | | — | | — | | — | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | (11.24 | ) | (11.22 | ) | (18.13 | ) | (36.43 | ) | (16.42 | ) |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | — | | — | | — | | — | | — | |
Other(4) | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 10,140 | | 10,192 | | 10,025 | | 9,792 | | 10,037 | |
Natural Gas (mmcf/d) | | — | | — | | — | | — | | — | |
Natural Gas Liquids (bbl/d) | | 703 | | 989 | | 627 | | 844 | | 790 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 52.14 | | 62.95 | | 40.93 | | 38.56 | | 48.72 | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | (24.55 | ) | 33.00 | | 24.72 | | 26.80 | | 17.06 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 22.27 | | 15.83 | | 19.99 | | 22.86 | | 20.21 | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | (18.79 | ) | 5.07 | | 17.11 | | 17.05 | | 5.47 | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 9.80 | | 8.44 | | 11.32 | | 13.03 | | 10.63 | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | 9.80 | | 8.44 | | 11.32 | | 13.03 | | 10.63 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 20.06 | | 38.68 | | 9.62 | | 2.68 | | 17.88 | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | (15.56 | ) | 19.49 | | (3.71 | ) | (3.28 | ) | 0.96 | |
TOTAL CONSOLIDATED ENTITIES | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 61,089 | | 59,281 | | 51,575 | | 41,597 | | 53,328 | |
Tight Oil (bbl/d) | | 12,228 | | 11,257 | | 10,756 | | 11,656 | | 11,472 | |
Shale Gas (mmcf/d) | | 578 | | 570 | | 586 | | 589 | | 581 | |
Natural Gas (mmcf/d) | | 720 | | 727 | | 685 | | 723 | | 713 | |
Natural Gas Liquids (bbl/d) | | 27,120 | | 25,670 | | 24,000 | | 25,708 | | 25,616 | |
Heavy Oil (bbl/d) | | 10,051 | | 10,275 | | 10,246 | | 10,192 | | 10,190 | |
59
| | Quarter Ended | | Total Year | |
| | 31-Mar | | 30-Jun | | 30-Sep | | 31-Dec | | 2015 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 53.42 | | 64.32 | | 42.90 | | 39.88 | | 51.22 | |
Tight Oil ($/bbl) | | 38.54 | | 35.95 | | 40.78 | | 35.31 | | 37.61 | |
Shale Gas ($/mcf) | | 2.61 | | 2.20 | | 2.19 | | 1.94 | | 2.23 | |
Natural Gas ($/mcf) | | 5.12 | | 4.99 | | 4.66 | | 4.01 | | 4.70 | |
Natural Gas Liquids ($/bbl) | | 21.52 | | 24.26 | | 20.46 | | 20.28 | | 21.64 | |
Heavy Oil ($/bbl) | | 33.46 | | 46.34 | | 33.73 | | 28.63 | | 35.56 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 13.71 | | 14.91 | | 12.47 | | 15.34 | | 14.06 | |
Tight Oil ($/bbl) | | 6.07 | | 11.73 | | 11.07 | | 9.25 | | 9.45 | |
Shale Gas ($/mcf) | | 0.43 | | 0.36 | | 0.37 | | 0.27 | | 0.35 | |
Natural Gas ($/mcf) | | 1.19 | | 1.19 | | 1.14 | | 1.00 | | 1.13 | |
Natural Gas Liquids ($/bbl) | | 3.63 | | 5.88 | | 3.90 | | 5.14 | | 4.64 | |
Heavy Oil ($/bbl) | | 3.00 | | 2.78 | | 2.84 | | 1.89 | | 2.63 | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 26.09 | | 24.53 | | 25.04 | | 20.21 | | 24.27 | |
Tight Oil ($/bbl) | | 13.01 | | 1.25 | | 7.96 | | 4.78 | | 6.83 | |
Shale Gas ($/mcf) | | 1.66 | | 1.28 | | 1.19 | | 1.31 | | 1.36 | |
Natural Gas ($/mcf) | | 1.34 | | 1.17 | | 1.21 | | 1.23 | | 1.25 | |
Natural Gas Liquids ($/bbl) | | 11.04 | | 2.89 | | 5.76 | | 5.71 | | 6.43 | |
Heavy Oil ($/bbl) | | 15.72 | | 7.98 | | 11.60 | | 8.39 | | 10.89 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 13.63 | | 24.87 | | 5.39 | | 4.33 | | 12.89 | |
Tight Oil ($/bbl) | | 19.46 | | 22.97 | | 21.75 | | 21.28 | | 21.33 | |
Shale Gas ($/mcf) | | 0.52 | | 0.55 | | 0.63 | | 0.37 | | 0.52 | |
Natural Gas ($/mcf) | | 2.59 | | 2.63 | | 2.31 | | 1.79 | | 2.32 | |
Natural Gas Liquids ($/bbl) | | 6.85 | | 15.49 | | 10.80 | | 9.43 | | 10.58 | |
Heavy Oil ($/bbl) | | 14.74 | | 35.58 | | 19.29 | | 18.35 | | 22.04 | |
EQUITY INVESTMENTS | | | | | | | | | | | |
TSEUK | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 15,250 | | 19,534 | | 19,685 | | 23,956 | | 19,630 | |
Natural Gas (mmcf/d) | | 2 | | 5 | | 5 | | 3 | | 4 | |
Natural Gas Liquids (bbl/d) | | 117 | | 177 | | 190 | | 35 | | 130 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 56.07 | | 61.63 | | 53.18 | | 44.08 | | 53.03 | |
Natural Gas ($/mcf) | | 6.56 | | 4.85 | | 4.74 | | 1.81 | | 4.39 | |
Natural Gas Liquids ($/bbl) | | 32.49 | | 44.25 | | 33.97 | | (39.44 | ) | 32.12 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 0.49 | | 0.46 | | 0.18 | | 0.24 | | 0.33 | |
Natural Gas ($/mcf) | | — | | — | | — | | — | | — | |
Natural Gas Liquids ($/bbl) | | — | | — | | — | | — | | — | |
60
| | Quarter Ended | | Total Year | |
| | 31-Mar | | 30-Jun | | 30-Sep | | 31-Dec | | 2015 | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 92.94 | | 62.05 | | 67.40 | | 46.92 | | 64.66 | |
Natural Gas ($/mcf) | | 0.70 | | 0.06 | | 0.07 | | 0.69 | | 0.28 | |
Natural Gas Liquids ($/bbl)(1) | | 3.93 | | 0.34 | | 0.39 | | 3.87 | | 1.57 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | (37.35 | ) | (0.88 | ) | (14.40 | ) | (3.08 | ) | (11.96 | ) |
Natural Gas ($/mcf) | | 5.86 | | 4.79 | | 4.67 | | 1.12 | | 4.11 | |
Natural Gas Liquids ($/bbl) | | 28.56 | | 43.91 | | 33.58 | | (43.31 | ) | 30.55 | |
Equion | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 10,764 | | 10,237 | | 11,895 | | 12,365 | | 11,321 | |
Natural Gas (mmcf/d) | | 43 | | 40 | | 41 | | 44 | | 42 | |
Natural Gas Liquids (bbl/d) | | — | | 2,316 | | 1,435 | | 1,446 | | 1,304 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 43.62 | | 61.28 | | 47.51 | | 38.94 | | 47.34 | |
Natural Gas ($/mcf) | | 3.79 | | 3.96 | | 4.17 | | 3.61 | | 3.88 | |
Natural Gas Liquids ($/bbl) | | — | | 14.84 | | 14.77 | | 13.78 | | 14.52 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 8.48 | | 12.51 | | 9.50 | | 7.79 | | 9.47 | |
Natural Gas ($/mcf) | | 0.92 | | 0.82 | | 0.24 | | 1.07 | | 0.76 | |
Natural Gas Liquids ($/bbl) | | — | | — | | — | | — | | — | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 6.03 | | 8.22 | | 7.90 | | 8.45 | | 7.63 | |
Natural Gas ($/mcf) | | 1.69 | | 1.42 | | 1.12 | | 1.22 | | 1.36 | |
Natural Gas Liquids ($/bbl)(1) | | 9.49 | | 7.97 | | 6.29 | | 6.85 | | 7.64 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 29.11 | | 40.56 | | 30.11 | | 22.70 | | 30.24 | |
Natural Gas ($/mcf) | | 1.18 | | 1.72 | | 2.81 | | 1.32 | | 1.76 | |
Natural Gas Liquids ($/bbl) | | (9.49 | ) | 6.87 | | 8.48 | | 6.93 | | 6.88 | |
TOTAL EQUITY INVESTMENTS | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 26,014 | | 29,771 | | 31,580 | | 36,321 | | 30,951 | |
Natural Gas (mmcf/d) | | 45 | | 45 | | 46 | | 47 | | 46 | |
Natural Gas Liquids (bbl/d) | | 117 | | 2,493 | | 1,625 | | 1,481 | | 1,434 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 50.92 | | 61.51 | | 51.04 | | 42.33 | | 50.95 | |
Natural Gas ($/mcf) | | 3.91 | | 4.05 | | 4.23 | | 3.49 | | 3.92 | |
Natural Gas Liquids ($/bbl) | | 32.49 | | 16.92 | | 17.01 | | 12.52 | | 16.12 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 3.80 | | 4.60 | | 3.69 | | 2.81 | | 3.67 | |
Natural Gas ($/mcf) | | 0.88 | | 0.73 | | 0.21 | | 1.00 | | 0.70 | |
Natural Gas Liquids ($/bbl) | | — | | — | | — | | — | | — | |
61
| | Quarter Ended | | Total Year | |
| | 31-Mar | | 30-Jun | | 30-Sep | | 31-Dec | | 2015 | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 56.97 | | 43.54 | | 44.99 | | 33.82 | | 43.80 | |
Natural Gas ($/mcf) | | 1.65 | | 1.28 | | 1.01 | | 1.18 | | 1.27 | |
Natural Gas Liquids ($/bbl)(1) | | 9.26 | | 7.19 | | 5.67 | | 6.63 | | 7.13 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | (9.85 | ) | 13.37 | | 2.36 | | 5.70 | | 3.48 | |
Natural Gas ($/mcf) | | 1.38 | | 2.04 | | 3.01 | | 1.31 | | 1.95 | |
Natural Gas Liquids ($/bbl) | | 23.23 | | 9.73 | | 11.34 | | 5.89 | | 8.99 | |
TOTAL ROGCI(5) | | | | | | | | | | | |
Average Daily Production | | | | | | | | | | | |
Light Oil (bbl/d) | | 87,103 | | 89,052 | | 83,155 | | 77,918 | | 84,279 | |
Tight Oil (bbl/d) | | 12,228 | | 11,257 | | 10,756 | | 11,656 | | 11,472 | |
Shale Gas (mmcf/d) | | 578 | | 570 | | 586 | | 589 | | 581 | |
Natural Gas (mmcf/d) | | 765 | | 772 | | 731 | | 770 | | 759 | |
Natural Gas Liquids (bbl/d) | | 27,237 | | 28,163 | | 25,625 | | 27,189 | | 27,050 | |
Heavy Oil (bbl/d) | | 10,051 | | 10,275 | | 10,246 | | 10,192 | | 10,190 | |
Average Net Prices Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 52.67 | | 63.38 | | 45.99 | | 41.02 | | 51.12 | |
Tight Oil ($/bbl) | | 38.54 | | 35.95 | | 40.78 | | 35.31 | | 37.61 | |
Shale Gas ($/mcf) | | 2.61 | | 2.20 | | 2.19 | | 1.94 | | 2.23 | |
Natural Gas ($/mcf) | | 5.05 | | 4.94 | | 4.63 | | 3.98 | | 4.65 | |
Natural Gas Liquids ($/bbl) | | 21.57 | | 23.61 | | 20.24 | | 19.85 | | 21.35 | |
Heavy Oil ($/bbl) | | 33.46 | | 46.34 | | 33.73 | | 28.63 | | 35.56 | |
Royalties | | | | | | | | | | | |
Light Oil ($/bbl) | | 10.75 | | 11.47 | | 9.13 | | 9.50 | | 10.24 | |
Tight Oil ($/bbl) | | 6.07 | | 11.73 | | 11.07 | | 9.25 | | 9.45 | |
Shale Gas ($/mcf) | | 0.43 | | 0.36 | | 0.37 | | 0.27 | | 0.35 | |
Natural Gas ($/mcf) | | 1.17 | | 1.16 | | 1.08 | | 1.00 | | 1.10 | |
Natural Gas Liquids ($/bbl) | | 3.61 | | 5.36 | | 3.65 | | 4.86 | | 4.39 | |
Heavy Oil ($/bbl) | | 3.00 | | 2.78 | | 2.84 | | 1.89 | | 2.63 | |
Production Costs(2) | | | | | | | | | | | |
Light Oil ($/bbl) | | 35.31 | | 30.89 | | 32.62 | | 26.56 | | 31.44 | |
Tight Oil ($/bbl) | | 13.01 | | 1.25 | | 7.96 | | 4.78 | | 6.83 | |
Shale Gas ($/mcf) | | 1.66 | | 1.28 | | 1.19 | | 1.31 | | 1.36 | |
Natural Gas ($/mcf) | | 1.36 | | 1.18 | | 1.20 | | 1.22 | | 1.25 | |
Natural Gas Liquids ($/bbl) | | 11.03 | | 3.27 | | 5.76 | | 5.76 | | 6.46 | |
Heavy Oil ($/bbl) | | 15.72 | | 7.98 | | 11.60 | | 8.39 | | 10.89 | |
62
| | Quarter Ended | | Total Year | |
| | 31-Mar | | 30-Jun | | 30-Sep | | 31-Dec | | 2015 | |
Netback Received | | | | | | | | | | | |
Light Oil ($/bbl) | | 6.62 | | 21.03 | | 4.24 | | 4.97 | | 9.43 | |
Tight Oil ($/bbl) | | 19.46 | | 22.97 | | 21.75 | | 21.28 | | 21.33 | |
Shale Gas ($/mcf) | | 0.52 | | 0.55 | | 0.63 | | 0.37 | | 0.52 | |
Natural Gas ($/mcf) | | 2.52 | | 2.60 | | 2.35 | | 1.76 | | 2.30 | |
Natural Gas Liquids ($/bbl) | | 6.92 | | 14.98 | | 10.83 | | 9.24 | | 10.49 | |
Heavy Oil ($/bbl) | | 14.74 | | 35.58 | | 19.29 | | 18.35 | | 22.04 | |
(1) NGL cost = Natural gas cost x 5.615.
(2) Production costs include transportation expense.
(3) Latin America does not include the Company’s investment in Equion, shown separately under “Equity Investments” in the table.
(4) Other refers to Algeria.
(5) Total Consolidated Entities plus Total Equity Investments.
63
REPORT ON RESERVES DATA BY THE COMPANY’S INTERNAL QUALIFIED RESERVES EVALUATOR
To the Board of Directors of Repsol Oil & Gas Canada Inc. (the “Company”):
1. The Company’s staff and I have evaluated the Company’s reserves data as at December 31, 2015 prepared in accordance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators. 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, and includes estimates in relation to the Company’s equity investees, Talisman Sinopec Energy UK Limited and Equion Energia Limited.
2. The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with the principles and definitions presented in the COGE Handbook.
4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2015:
Location of Reserves | | Net Present Value of Future Net Revenue
(Before Income Taxes, 10% Discount Rate)
($ millions) | |
Canada | | 1,302.5 | |
US | | 3,250.6 | |
Southeast Asia | | 5,484.6 | |
Latin America(1) | | 111.6 | |
Other | | 466.2 | |
Equity Investments(2) | | (1,181.4 | ) |
TOTAL | | 9,434.1 | |
1) Latin America does not include net present value of future net revenue attributable to the Company’s equity investments, shown separately under “Equity Investments” in this table.
2) Equity Investments includes the Company’s investments in Equion and TSEUK.
5. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied.
6. We have no responsibility to update our evaluation for events and circumstances occurring after its preparation date.
7. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
(signed) “Mark Ireland”
Mark Ireland
Internal Qualified Reserves Evaluator
Repsol Oil & Gas Canada Inc.
Calgary, Alberta
February 26, 2016
64
REPORT OF MANAGEMENT AND DIRECTORS ON NI 51-101 RESERVES DATA AND OTHER INFORMATION
Management of Repsol Oil & Gas Canada Inc. (the “Company”) is responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2015, estimated using forecast prices and costs, prepared in accordance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) of the Canadian Securities Administrators.
The Company’s reserves evaluation staff, including its Internal Qualified Reserves Evaluator who is an employee of the Company, have evaluated the Company’s reserves data. The report of the Internal Qualified Reserves Evaluator will be filed with securities regulatory authorities concurrently with this report.
The board of directors of the Company has:
a) reviewed the Company’s procedures for providing information to the Internal Qualified Reserves Evaluator;
b) met with the Internal Qualified Reserves Evaluator to determine whether any restrictions affected the ability of the Internal Qualified Reserves Evaluator to report without reservation; and
c) reviewed the reserves data with management and the Internal Qualified Reserves Evaluator.
The board of directors of the Company has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has approved:
a) the content and filing with securities regulatory authorities of the reserves data and other oil and gas information prepared in accordance with the requirements of NI 51-101, contained in the Annual Information Form of the Company;
b) the filing of Form 51-101F2, which is the report of the Internal Qualified Reserves Evaluator on the reserves data; and
c) the content and filing of this report.
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
(signed) “Luis Cabra Dueñas” Luis Cabra Dueñas
Chief Executive Officer | | (signed) “Josu Jon Imaz San Miguel” Josu Jon Imaz San Miguel
Chairman |
| | |
(signed) “David S. Newby” David S. Newby
Senior Vice President Finance, Treasurer
and Chief Financial Officer | | (signed) “Michael T. Waites” Michael T. Waites
Director |
February 26, 2016
65
SCHEDULE B — AUDIT COMMITTEE INFORMATION
Composition of Audit Committee
As at February 25, 2016, the Company’s Audit Committee consists of Michael T. Waites (Chairman), Albrecht W.A. Bellstedt, and Thomas W. Ebbern . The Board of Directors has determined that all members of the Audit Committee are “independent” and “financially literate” as defined in National Instrument 52-110 (“NI 52-110”).
NI 52-110 states that a member of an audit committee is independent if the member has no direct or indirect material relationship with the issuer. A material relationship is a relationship which could, in the view of the issuer’s Board of Directors, reasonably interfere with the exercise of a member’s independent judgment.
In addition, an individual is considered financially literate if he or she has 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 the issues that can reasonably be expected to be raised by the issuer’s financial statements.
Education and Experience
The members of the Company’s Audit Committee have education and experience relevant to the performance of their responsibilities as Audit Committee members, which includes the following:
Albrecht Bellstedt has been a professional director since February 2007. Previously (and from 1999 to 2007), Mr. Bellstedt served as Executive Vice-President and General Counsel of TransCanada Corporation and a predecessor corporation. Prior to that, he was a transactional lawyer in private practice for 27 years. Mr. Bellstedt holds a Juris Doctor from the University of Toronto and a Bachelor of Arts degree from Queen’s University.
Thomas Ebbern has been Chief Financial Officer of North West Upgrading Inc. since January 2012. He was formerly Managing Director, Investment Banking, of Macquarie Capital Markets Canada Ltd., a subsidiary of Macquarie Group Limited. Prior to that he was Managing Director of Tristone Capital Inc., an energy advisory firm that was acquired by Macquarie. He began his career as a geophysicist with Gulf Canada in 1982. Mr. Ebbern holds a Bachelor of Science degree in Geological Engineering from Queen’s University and a Master of Business Administration from the Richard Ivey School of Business at the University of Western Ontario.
Michael Waites was President and Chief Executive Officer of Finning International Inc. from May 2008 until his retirement from Finning in May 2013. Prior to that, Mr. Waites was Executive Vice President and Chief Financial Officer of Finning. He also served as a member of the board of directors of Finning for three years prior to his appointment as Executive Vice President and Chief Financial Officer. Prior to joining Finning in May 2006, Mr. Waites was Executive Vice President and Chief Financial Officer at Canadian Pacific Railway since July 2000, and was also Chief Executive Officer U.S. Network of Canadian Pacific Railway. Previously, he was Vice President and Chief Financial Officer at Chevron Canada Resources. Mr. Waites holds a Bachelor of Arts (Honours) in Economics from the University of Calgary, a Master of Business Administration from Saint Mary’s College of California, and a Master of Arts, Graduate Studies in Economics from the University of Calgary. He has also completed the Executive Program at The University of Michigan Business School.
Audit Fees and Pre-Approval of Audit Services
The following table presents fees for the audits of the Company’s annual Consolidated Financial Statements for 2015 and 2014 and for other services provided by Ernst & Young LLP:
(C$) | | 2015 | | 2014 | |
Audit Fees | | 5,412,669 | | 5,274,251 | |
Audit-Related Fees | | 337,859 | | 733,730 | |
Tax Fees | | 293,167 | | 504,785 | |
All Other Fees(1) | | 13,654 | | 117,376 | |
Total | | 6,057,349 | | 6,630,142 | |
(1) Consulting and annual subscription to online accounting database.
The audit-related fees are primarily for assistance in connection with the Company’s prospectus filings, pension plan audits and attestation procedures related to cost certifications and government compliance. Tax fees are primarily for tax
66
compliance and tax advisory services. The Audit Committee has concluded that the provision of tax services is compatible with maintaining Ernst & Young’s independence.
Under the terms of reference of the Audit Committee, which follow, the Audit Committee is required to review and pre-approve the objectives and scope of the external audit work and proposed fees. In addition, the Audit Committee is required to review and pre-approve all non-audit services, including tax services, the Company’s external auditors are to perform.
During 2003, the Audit Committee implemented specific procedures regarding the pre-approval of services to be provided by the Company’s external auditors. These procedures specify certain prohibited services that are not to be performed by the Company’s external auditors. In addition, these procedures require that, at least annually, prior to the period in which the services are proposed to be provided, the Company’s management, in conjunction with the Company’s external auditors, prepares and submits to the Audit Committee a complete list of all proposed services and related fees to be provided to the Company by the Company’s external auditors. Under the Audit Committee pre-approval procedures, for those non-audit services proposed to be provided by the Company’s external auditors that have not been previously approved by the Audit Committee, the Audit Committee has delegated to the Chairman of the Audit Committee, and to management up to a fixed value, the authority to grant pre-approvals of such services. The decision to pre-approve a service covered under this procedure is presented to the full Audit Committee at the next scheduled meeting. At each of the Audit Committee’s regular meetings, the Audit Committee is provided an update as to the status of services previously approved.
Pursuant to these procedures since their implementation in 2003, 100% of each of the services relating to fees reported as audit-related, tax and all other were pre-approved by the Audit Committee or its delegate, the Chair of the Audit Committee, or management within its delegated authority.
The full text of the terms of reference for the Company’s Audit Committee follows.
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TERMS OF REFERENCE
Audit Committee
Mission Statement
The Audit Committee’s mission is to assist the Board in fulfilling its obligations by overseeing and monitoring the Corporation’s financial accounting and reporting process and the integrity of the Corporation’s financial statements and its internal control over financial reporting and the external financial audit process. To fulfill this mission, the Audit Committee has received this mandate and has been delegated certain authorities that it may exercise on behalf of the Board.
Composition
At the first meeting of the Board of Directors of the Corporation after the election of Directors at the annual meeting of shareholders (or a shareholder resolution in lieu thereof), the Board shall appoint an Audit Committee comprised of not less than three Directors of the Corporation. Each member of the Audit Committee shall be independent and all members of the Audit Committee shall have an appropriate level of financial literacy, all as required under applicable securities laws and determined by the Board from time to time. The Board may replace or remove from the Audit Committee any member at any time.
The Chair of the Audit Committee shall be appointed by the Board at the meeting of the Board referred to above. The Chair shall preside as chair at each Committee meeting, lead Committee discussion on meeting agenda items and report to the Board, on behalf of the Committee, with respect to the proceedings of each Committee meeting. The Audit Committee shall designate a Secretary to the Audit Committee who may be a member of the Audit Committee or an officer or employee of the Corporation. The Secretary shall keep minutes and records of all meetings of the Audit Committee. In the event that either the Chair or the Secretary is absent from any meeting, the members present shall designate any Director present to act as Chair and shall designate any Director, officer or employee of the Corporation to act as Secretary.
Meetings
Meetings of the Audit Committee, including telephone conference meetings, shall be held at such time and place as the Chair of the Audit Committee or a majority of the Committee members may determine. In addition, at the request of the external auditor of the Corporation (the “Auditor”), the Chief Executive Officer, or the Chief Financial Officer (or persons acting in such capacity), the Chair shall call and convene a meeting of the Audit Committee.
Notice of meetings shall be given to each member not less than 24 hours before the time of the meeting, provided that meetings of the Audit Committee may be held without formal notice if all of the members are present and do not object to notice not having been given, or if those absent waive notice in any manner before or after the meeting.
Notice of meeting will be given in writing and may be delivered personally, given by mail, facsimile or other electronic communication and need not be accompanied by an agenda or any other material. The notice shall however specify the purpose or purposes for which the meeting is being held.
Fifty percent (50%) of the directors duly appointed as Committee members and in attendance shall constitute a quorum for the transaction of business at any meeting of the Audit Committee. No business may be transacted by the Audit Committee except at a meeting of its members at which a quorum of the Audit Committee is present.
The Audit Committee shall meet at least quarterly.
Representatives of the Auditor and management of the Corporation shall have access to the Audit Committee each in the absence of the other.
The Auditor shall be notified of all meetings of the Audit Committee and, when appropriate, it may attend and be heard at any such meeting and shall attend if requested to do so by a member of the Audit Committee.
Any matter the Audit Committee does not unanimously approve will be referred to the Board for consideration.
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Amendments
No alteration to the roles and responsibilities of the Audit Committee shall be effective without the approval of the Board of Directors.
The Audit Committee shall review the adequacy of these Terms of Reference on an annual basis and recommend any changes it considers appropriate to the Board of Directors for consideration and approval.
Role and Responsibilities
A. Financial Statements and Other Financial Information
The Audit Committee shall oversee the Corporation’s financial reporting process on behalf of the Board and report on the results of these activities to the Board including:
1. review the Corporation’s interim and annual financial statements and management’s discussion and analysis of operations which accompanies such financial statements and, if determined to be satisfactory, in the case of the interim documents, approve them, and in the case of the annual documents, recommend them to the Board for approval;
2. review the interim and annual earnings press release prior to their filing or publication;
3. ensure that adequate procedures are in place for the review of the Corporation’s public disclosure of financial information extracted or derived from the Corporation’s financial statements, other than the public disclosure referred to in items 1 and 2 above, and periodically assess the adequacy of those procedures;
4. review the appropriateness of any report or opinion proposed to be rendered in connection with the year end consolidated financial statements;
5. review the nature, substance and appropriateness of significant accruals, reserves and other estimates;
6. review the appropriateness of impairment provisions;
7. review with the Auditor and with the management of the Corporation and, if determined to be satisfactory, approve on behalf of the Board all financial statements included in a prospectus or other similar document; and
8. review and assess regularly:
(a) the quality and acceptability of accounting policies and financial reporting practices used by the Corporation;
(b) any significant new or proposed changes in financial reporting and accounting policies, practices or standards that may affect or be adopted by the Corporation;
(c) the key financial estimates and judgments of management that may be material to the financial reporting of the Corporation;
(d) policies related to financial disclosure risk assessment and management;
(e) responses by management to material information requests from government or regulatory authorities which may have an impact on the financial reporting of the Corporation; and
(f) presentations given by management and the Auditor regarding the accounting treatment of large transactions.
9. appoint and, where necessary, terminate auditors of the Corporation’s pension plans, based on advice from the Pension Management Committee.
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B. External Audit
The Auditor shall be ultimately accountable to the shareholder of the Corporation, who shall be represented by the Board of Directors and the Audit Committee in its dealings with the Auditor. The Audit Committee shall recommend to the Board the auditor that will be proposed at the annual shareholders’ meeting (or shareholder resolution in lieu thereof) for appointment as the Auditor for the ensuing year. The Auditor shall report directly to the Audit Committee, which shall be responsible for compensation and retention of the Auditor and oversight of the Auditor’s work (including resolution of disagreements between management and the Auditor regarding financial reporting).
At least annually, the Audit Committee shall require that the Auditor provide a formal written statement describing: (i) the firm’s internal quality-control procedures; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the firm, 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 firm, and any steps taken to deal with any such issues; and (iii) all relationships between the Auditor and the Corporation (see also section D).
With respect to (iii) above and for more clarity, annually the Audit Committee shall obtain a written letter from the Auditor pursuant to the Independence Standards Board standard #1 disclosing all relationships between the Auditor and its related entities and the Corporation and its related entities, and confirming the Auditor’s independence from the Corporation.
The Audit Committee shall not recommend to the Board that an auditor be appointed as the Auditor if the Corporation’s Chief Executive Officer, Chief Financial Officer or Controller (or persons acting in that capacity) was employed by the auditor and participated in any capacity in the Corporation’s audit during the one-year period preceding the date of the initiation of the Corporation’s audit for which the Audit Committee is recommending the appointment. The Audit Committee shall review management’s policies for hiring partners, employees and former partners and employees of the Auditor and former external auditor of the Corporation. The Audit Committee further shall ensure the independence of the Auditor by reviewing, and discussing with the Board if necessary, any relationships that may adversely affect the independence of the Auditor.
The Audit Committee shall review the planning and results of external audit activities and the ongoing relationship with the Auditor. In this regard the Audit Committee shall:
1. review and, if determined to be satisfactory, pre-approve the terms of the annual external audit engagement plan, including but not limited to the following:
(a) engagement letter;
(b) objectives and scope of the external audit work;
(c) materiality limit;
(d) areas of audit risk;
(e) staffing;
(f) timetable; and
(g) proposed fees.
2. annually, or as otherwise required by the Audit Committee, review a written report from the Auditor on the critical accounting policies of the Corporation;
3. review and, if determined to be satisfactory, pre-approve all non-audit services, including tax services, the Auditor is to perform, and it shall consider the impact the provision of such services could have on the independence of the external audit work. The Audit Committee may delegate this authority to grant pre-approvals to one or more designated members of the Audit Committee, provided that such delegates present their decisions to pre-approve services to the full Audit Committee at each of its scheduled meetings. The Audit Committee shall not permit the Auditor to perform any non-audit service prohibited by law applicable to the Corporation;
4. meet with the Auditor and management to discuss the Corporation’s annual financial statements and the Auditor’s report, the interim financial statements, and management’s discussion and analysis relating to both the annual and
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interim financial statements. Meetings with the Auditor and management shall be held separately, periodically, as scheduled by the Audit Committee;
5. review and advise the Board with respect to the conduct and reporting of the annual external audit, including but not limited to the following:
(a) any audit problems or difficulties encountered, and management’s response thereto, and any restriction imposed by management during the annual audit;
(b) any significant accounting or financial reporting issue;
(c) the Auditor’s evaluation of the Corporation’s system of internal controls and related procedures and documentation;
(d) the post audit or management letter containing any of the Auditor’s findings or recommendations, including management’s response thereto and the subsequent follow-up to any identified control weaknesses; and
(e) any other matters that the Auditor brings to the attention of the Audit Committee.
6. prepare an Audit Committee report to be included in the Corporation’s annual corporate governance disclosure; and
7. fix the remuneration of the Auditor.
C. Internal Audit
The Audit Committee shall oversee the internal audit function of the Corporation and the relationship of the internal auditor with management. Periodically, the Audit Committee shall meet separately with each of the internal auditor and management. To this end, the Audit Committee shall:
1. review and consider the appropriateness of the internal audit function and organizational framework, including approving the internal audit plan and resources;
2. review and approve the internal audit charter if and as appropriate;
3. be involved in the appointment or removal of the lead internal auditor for the Corporation;
4. support the independence of the internal audit function and the internal auditor; and
5. review the findings of the internal auditor for purposes of considering the appropriateness of follow-up plans
D. Internal Financial Control and Information Systems
The Audit Committee will review and obtain reasonable assurance that the internal financial control and information systems are operating effectively to produce accurate, appropriate and timely financial information. In this regard the Audit Committee will:
1. obtain reasonable assurance by discussions with and reports from management, the internal auditor and the Auditor, that:
(a) the internal financial control information systems, security of information and disaster recovery plans are adequate and reliable; and
(b) the internal control systems and procedures are properly designed and effectively implemented.
2. review the appointment of the Chief Financial Officer (or person acting in that capacity) prior to his or her appointment and the adequacy of accounting and finance resources, as required; and
3. ensure that direct and open communication exists among the Audit Committee and the Auditor and, if requested, with the internal audit organization of the Corporation’s ultimate shareholder.
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E. Financial Risk Oversight, Insurance
The Audit Committee shall discuss with management the Corporation’s material financial risk exposures and review the steps management has taken to monitor, control, report and mitigate such risk to the Corporation. The Audit Committee will also consider insurance coverage of significant business risks and uncertainties.
F. Subsidiaries
The Audit Committee shall receive a report on the Corporation’s material Subsidiaries, as requested from time to time, concerning any material non-routine structures e.g. special purpose entities, off balance sheet items or partnership arrangements.
G. Tax
The Audit Committee shall receive regular reports from management on the status of tax filings including:
(a) the status of accounts for withholdings from employees and remittances of source deductions, as well as any required remittances for sales taxes and excise duty;
(b) confirmation that returns, withholdings and remittances have been made during relevant periods; and
(c) if applicable, major associated issues.
H. Legal
The Audit Committee shall receive periodic reports from the General Counsel (or person acting in that capacity) on legal matters affecting financial disclosure, including claims, potential claims and changes to legislation.
I. Investigations and Access to Management
The Audit Committee shall have the authority to direct and to supervise the investigation into any matter brought to its attention within the scope of its duties. It shall establish procedures for the receipt, retention and treatment of (i) complaints the Corporation may receive regarding accounting, internal accounting controls, or auditing matters, and (ii) confidential, anonymous submissions from Corporation employees expressing concern regarding questionable accounting or auditing matters.
The Audit Committee has the authority to engage independent counsel and other advisers having special competencies, as it determines necessary to carry out its duties. The Audit Committee shall determine the appropriate amount of funding the Corporation shall provide for compensation of any such advisors.
In carrying out its responsibilities, the Audit Committee shall have access to such members of the Corporation’s management as appropriate, including the persons having responsibility for:
(a) foreign currency and interest rate exposure and related derivatives;
(b) tax exposures and related reserves;
(c) internal financial control systems security and system integrity recovery plans;
(d) compliance with domestic and international regulatory requirements (such as the Corruption of Foreign Public Officials Act and Foreign Corrupt Practices Act) and material legal exposures; and
(e) financial accounting.
The Audit Committee shall receive from management copies of any report or inquires of a material nature from regulators or government bodies which is relevant to the responsibilities of the Audit Committee set out in this mandate and of management’s responses thereto.
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J. General
The Audit Committee shall review corporate policies that are within the scope of the roles and responsibilities specified by these terms of reference prior to submission for approval by the Board; monitor compliance on a regular basis; and ensure these policies are periodically reviewed and kept current.
The Audit Committee shall perform such other duties as may be assigned to it by the Board from time to time or as may be required by applicable law.
In respect of matters within its purview under this mandate and delegation, the Audit Committee shall assist the Board in its oversight of the Corporation’s compliance with legal and regulatory requirements.
The Audit Committee shall report to the Board at each regularly scheduled Board meeting next succeeding any Committee meeting.
The Audit Committee shall evaluate its own performance annually.
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SCHEDULE C — CORPORATE GOVERNANCE
CORPORATE GOVERNANCE DISCLOSURE
This Schedule describes the Company’s corporate governance framework, including the structures and processes regarding the direction, management and oversight of the Company.
Background
Repsol Transaction
The Repsol Transaction was completed on May 8, 2015. The effect of the transaction was that the Company became an indirect wholly-owned subsidiary of Repsol, with all equity voting securities of the Company being held by a single shareholder. As a result, some of the Company’s corporate governance practices have changed from those which existed prior to completion of the Repsol Transaction. The disclosure in this Schedule relates to the Company’s corporate governance practices subsequent to the completion of the Repsol Transaction.
Corporate Governance Changes Following Acquisition
Immediately following the closing of the Repsol Transaction:
· all directors except Michael T. Waites and Thomas W. Ebbern resigned;
· the size of the Board of Directors (the “Board”) was fixed at nine members; and
· the Company’s sole shareholder elected nine directors, including Messrs. Waites and Ebbern.
At the first directors’ meeting following the closing of the Repsol Transaction, the newly elected Board approved the following changes to the Company’s corporate governance framework;
· the continued constitution of the Audit Committee;
· the cessation of all other previously existing Board Committees (and specifically, disbanding the Human Resources Committee, Governance and Nominating Committee, Reserves Committee and Health, Safety, Environment and Corporate Responsibility Committee);
· the appointment of three independent directors as members of the Audit Committee, as well as the appointment of an Audit Committee Chairman; and
· terms of reference for each of the Board of Directors and Audit Committee.
The Board has since approved terms of reference for the Chairman of the Board and Chief Executive Officer (“CEO”), as well as updates to the Company’s Disclosure Policy which are described in more detail below.
Corporate Governance Principles
Code of Business Conduct and Ethics
The Company has adopted a Code of Business Conduct and Ethics (“CBCE”) which is applicable to all directors, officers and employees of the Company. To monitor compliance with the CBCE, certificates are required at least annually from all directors, worldwide employees and various consultants of the Company, which confirm compliance with the CBCE or disclose any deviations therefrom. The Company requires annual online ethics training as part of the certificate of compliance process. Exceptions are required to be noted directly to the CEO, and supervisors are notified if employees do not complete their annual certifications. Disclosures contained in the certificates, as well as a status report on the percentage of directors, employees and various consultants who have completed their annual certification, are reported to the Audit Committee for consideration. The Board of Directors reviews any requests for waivers from the CBCE from executive officers and directors, and all material waivers from the CBCE are required to be disclosed promptly to shareholders. No waivers from the CBCE were granted for the benefit of the Company’s directors or executive officers during the year ended December 31, 2015.
The Company values good faith actions in support of the CBCE and will not tolerate retaliation of any kind as a result of good faith reporting by employees. The Company requires that observed breaches of the CBCE be reported to a
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supervisor or manager, a Vice President in the Legal Department, the Director, Audit & Control, North America, an executive officer, or through the Integrity Matters hotline noted below.
The Company’s CBCE can be obtained from the Company’s website at www.repsol.com/ca_en/ com or upon request from: Communications and External Relations Department, Repsol Oil & Gas Canada Inc., 2000, 888 — 3rd Street S.W., Calgary, Alberta, T2P 5C5 or by email at: infocanada@repsol.com. The CBCE, as last updated in 2014, has been filed with Canadian securities regulators and can be accessed through www.sedar.com.
Disclosure Policy
The Company has a Disclosure Policy which applies to directors, employees and third parties who represent the Company and its subsidiaries. The objectives of the Disclosure Policy are to: (1) ensure compliance with all applicable legal and regulatory requirements relating to disclosure; (2) ensure that the Company broadly disseminates information, when necessary, in a timely manner in order to keep security holders and capital markets appropriately informed regarding the Company; (2) prevent improper use or disclosure of material information and to give guidance on dealing with other confidential information pertaining to the Company; (3) raise awareness of disclosure requirements and the Company’s approach to disclosure; (4) provide guidance concerning communicating corporate information to investors, industry analysts, members of the media and debt holders. Pursuant to the Disclosure Policy, a Disclosure Committee has been constituted and is comprised of members of senior management of the Company. In addition, ongoing disclosure training is provided to targeted groups within the Company. The Disclosure Policy was last updated in December 2015 to reflect: the fact that the Company has one shareholder and has been delisted from the New York Stock Exchange and Toronto Stock Exchange; and new organizational structures and titles.
Ethics Hotline
The Company maintains a confidential and anonymous reporting hotline for submitting inquiries or complaints regarding ethics matters and other areas of concern, such as human resources or workplace practices. This Integrity Matters hotline is available to internal and external users, and reports are received by an independent third party provider and subsequently forwarded to the Company’s Ethics Coordinator. In addition, the Company has a Global Investigation Policy and has developed investigation procedures and protocols. All matters reported through the Integrity Matters hotline in 2015 were reviewed by the Ethics Coordinator for possible breaches of Company policies, and actions were taken where appropriate. The Audit Committee has developed procedures for the receipt, retention and treatment of complaints received regarding accounting, internal accounting controls or auditing matters. Any reports made through the Integrity Matters hotline which relate to these areas are subject to the parameters and notification protocols embedded in the Audit Committee procedures.
Role of the Board and its Committees
Board Roles and Responsibilities
The Board sees its principal role as stewardship of the Company and its fundamental objective as the creation of shareholder value, including the protection and enhancement of the value of the Company’s assets. The Board’s stewardship responsibility means that it oversees the conduct of the business and management, which is responsible for conducting the Company’s day-to-day business. The Board, through senior management of the Company, sets the attitude and disposition of the Company toward compliance with applicable laws, environmental, safety and health policies, financial practices and reporting. In addition to its accountability to its shareholder, the Board is also accountable to employees, government authorities and other stakeholders.
The Board has developed and approved Terms of Reference for the Board which are reproduced in their entirety in Appendix “A” to this Schedule, and which are reviewed on an annual basis.
Position Descriptions
The Board has developed and approved written position descriptions for the Chairman of the Board, the CEO and the Audit Committee Chair.
Chairman of the Board
The principal role of the Chairman of the Board is to manage and provide leadership to the Board. The Chairman is accountable to the Board and acts as a direct liaison between the Board and management of the Company through the CEO. In addition, the Chairman acts as a communicator for Board decisions where appropriate. The Chairman’s mandate directs
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him to ensure that there is opportunity for the directors to hold discussions without management present at each Board meeting, and he presides at such sessions.
Chief Executive Officer
The CEO is responsible for leading the development and execution of the Company’s long term strategy with a view to creating shareholder value. The CEO acts as a direct liaison between the Board and management. The CEO is accountable to the Board.
Audit Committee Chair
The Chair of the Audit Committee leads committee discussion on meeting agenda items and reports to the Board, on behalf of the Committee, with respect to the proceedings of each committee meeting. The Chair of each Committee also reviews agendas, work plans and, as appropriate, substantive agenda items with members of management prior to each committee meeting.
Independence Determinations — Directors
Pursuant to National Instrument 58-101 (“NI 58-101”) and National Instrument 52-110, the Board of Directors has determined that each of Michael T. Waites, Thomas W. Ebbern and Albrecht W.A. Bellstedt are “independent.” Each of Josu Jon Imaz San Miguel, Luis Cabra Dueñas, Miguel Klingenberg Calvo, F. Javier Sanz Cedrón and M. Tomás García Blanco are not “independent” pursuant to NI 58-101 because they are employees of the Company’s ultimate shareholder, Repsol. In addition, Luis Cabra Dueñas serves as CEO of the Company. Robert R. Rooney is not “independent” as he served as an executive officer of the Company until May 8, 2015.
The Chairman of the Board, Josu Jon Imaz San Miguel, is not “independent” as noted above.
Independence Determinations — Audit Committee
The Audit Committee of the Board, including the Committee Chair, is currently composed entirely of independent directors.
Other and Interlocking Directorships
Certain directors of the Company serve as directors of other reporting issuers. The Board has not adopted a formal policy limiting the number of outside directorships of the Company’s directors.
In Camera Sessions
The Chairman of the Board is required to ensure that, regularly, upon completion of the ordinary business of a meeting of the Board, the directors have an opportunity to hold discussions without management present. Since May 8, 2015 the Board of Directors held 2 in camera sessions without management present. The non-independent directors were included in these sessions.
The Audit Committee, which is comprised entirely of independent directors, also holds in camera sessions without management present at least at the end of each regularly scheduled meeting. The Audit Committee also holds private sessions with each of the external auditor, the Director, Audit & Control, North America, and senior management following each regularly scheduled committee meeting. During 2015, the Audit Committee held 3 in camera sessions, which included non-independent directors who were present at the Audit Committee meetings.
Director Attendance
Board members are expected to attend Board meetings and meetings of Committees on which they are a member. The following sets forth the attendance record of each director for the period following completion of the Repsol Transaction.
Director | | 2015
Board Meetings
Attended | | 2015
Committee
Meetings
Attended | | 2015 Combined
Board
and Committee
Meetings
Attended | |
Albrecht W.A. Bellstedt | | 5 of 61 | | 4 of 4 | | 9 of 10 | |
Luis Cabra Dueñas | | 6 of 6 | | N/A2 | | 6 of 6 | |
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Director | | 2015
Board Meetings
Attended | | 2015
Committee
Meetings
Attended | | 2015 Combined
Board
and Committee
Meetings
Attended | |
Thomas W. Ebbern | | 6 of 6 | | 4 of 4 | | 10 of 10 | |
M. Tomás García Blanco | | 5 of 61 | | N/A2 | | 5 of 6 | |
Josu Jon Imaz San Miguel | | 5 of 61 | | N/A2 | | 5 of 6 | |
Miguel Klingenberg Calvo | | 6 of 6 | | N/A2 | | 6 of 6 | |
Robert R. Rooney | | 6 of 6 | | N/A2 | | 6 of 6 | |
F. Javier Sanz Cedrón | | 6 of 6 | | N/A2 | | 6 of 6 | |
Michael T. Waites | | 6 of 6 | | 4 of 4 | | 10 of 10 | |
(1) Due to schedule conflicts, Mr. Bellstedt could not attend one Board meeting and Messrs. Garcia and Imaz each could not attend one Board meeting that was not regularly scheduled.
(2) Not a member of the Audit Committee.
Director Orientation and Continuing Education
The Company is committed to ensuring its directors have the skills and knowledge necessary to meet their obligations as directors through director orientation sessions and continuing education sessions.
The director orientation and education activities that took place or were provided to directors from closing of the Repsol Transaction through December 31, 2015 included the following:
· Informational overview of director and officer liability (May 2015)
· Director orientation session regarding the profile and the reporting obligations associated with the Company’s public debt (July 2015)
· Director orientation session regarding the Company’s consolidated financial statements and related accounting implications (July 2015)
· Director orientation session regarding the Repsol framework of internal controls (July 2015)
· North American geo-political review with external speaker (December 2015)
Full Board participation is encouraged at all education sessions.
Individual Board members may also pursue educational opportunities independently, including attendance at industry conferences and subscriptions to industry publications.
The Audit Committee also regularly receives informational papers from management and the Company’s external auditor on trends and issues related to their mandate as part of their Audit Committee mailings.
Nomination of Directors
The Company’s director nomination process is led by the Company’s ultimate shareholder and takes into account both the legal and regulatory requirements applicable to the Company as well as the internal regulations of Repsol with respect to subsidiary director and officer appointments. Each director candidate is reviewed against his or her specific experiences and perspectives to assess his or her potential effectiveness as a director. For the composition of the Board following completion of the Repsol Transaction, Repsol determined that the ideal mix of skills and experience of the Company’s Board of Directors should be comprised of: individuals with executive or senior management experience in the Repsol group of companies, and particularly, those individuals who continued to sponsor integration and transformation initiatives post acquisition; individuals with operational experience in Repsol’s upstream division; independent directors with financial acumen and prior experience in the oil and gas industry; and a former executive officer with industry and corporate knowledge.
The Corporate Secretary reviews all existing and future commitments of each candidate, including other directorships, to determine: (a) if they impact a candidate’s independence or pose a potential conflict of interest; and (b) whether there are interlocking directorships.
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Diversity
The Company has not adopted a written policy relating to the identification and nomination of women directors. With respect to the representation of women in the director identification and selection process and executive officer appointments, a nominee or candidate’s diversity of gender, ethnicity, nationality, age, experience and geographic background or other attributes will be considered favorably in his or her assessment.
The Board has not adopted a target regarding women on the Board or women in executive officer positions. Currently, none of the Company’s Board members are women, and neither the Company nor its major subsidiaries have any women on their respective executive leadership teams.
The Company’s approach to diversity generally will be reviewed as part of the integration efforts with Repsol. In this regard, Repsol has principles on diversity which state that diversity is a source of added value for the global company, and that variety in terms of age, culture, professional profile, gender and different abilities contributes to the fostering of a culture of diversity which in turn feeds off different and innovative ideas and perspectives. In 2007, Repsol created a Diversity and Balance Committee which is responsible for improving how diversity is managed across all areas of the global company. It is expected that integration of the Company’s legacy talent management model with Repsol’s global programs will necessarily be required to comply with Repsol’s approach to diversity. Similarly, the Board Succession Policy in place prior to the closing of the Repsol Transaction (which contains term limits and commitments to diversity) will be re-examined as appropriate in support of the larger global initiative.
Performance Assessments
The Chairman of the Board, with the assistance of the CEO and the Corporate Secretary, is required to annually review and assess annually director attendance, performance, the size and composition of the Board. The Chairman of the Board, with the assistance of the CEO and Corporate Secretary, is also required to assess and make recommendations to the Board annually regarding the effectiveness of the Board as a whole, the committees of the Board and when and as applicable, individual directors.
To assist in this review, all directors are provided with a questionnaire that provides for quantitative ratings in key areas and seeks subjective comment on the performance and effectiveness of the Board and the Audit Committee. Suggestions for improvement and for director education and training activities are also requested from all directors. The responses to the questionnaires are reviewed and an action list is developed by the Corporate Secretary for review by the CEO and Chairman of the Board. The Chairman briefs the directors on the summary results of the assessment at the conclusion of the process.
Board Committees
The Board fulfils its role, to act in the best interests of the Company, directly and through committees to which it delegates certain responsibilities.
As a reporting issuer, the Company has an established Audit Committee. This standing Committee of the Board convenes in accordance with an annually developed schedule. The following describes the composition, responsibilities and key activities of this standing Committee.
Audit Committee Report
The Audit Committee is responsible for assisting the Board in fulfilling its obligations by overseeing and monitoring the Company’s financial accounting and reporting process. It is also responsible for overseeing and monitoring the integrity of the Company’s financial statements, its internal control over financial reporting and the external financial audit process, evaluating the independence of the Company’s auditor and overseeing the Company’s internal audit function. In fulfilling its responsibilities, the Audit Committee meets regularly with the internal and external auditors and management. The Terms of Reference of the Audit Committee require that each member be independent and, as such, all members of the Audit Committee are unrelated, independent directors.
The Audit Committee is committed to compliance with all applicable accounting policies, procedures and related controls. In accordance with the requirements of the US Securities Exchange Act of 1934, as amended, and NI 52-110, the Audit Committee has adopted procedures for (a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls or auditing matters; and (b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters.
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Members from May 11, 2015 to the date of this Annual Information Form are:
Michael T. Waites (Chair)
Thomas W. Ebbern
Albrecht W. A. Bellstedt
All Committee members are financially literate. Additional information on the Company’s Audit Committee, including the Terms of Reference for the Audit Committee, a description of Audit Committee members’ education and experience, and a summary of external auditor fees is contained in Schedule B to this Annual Information Form.
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APPENDIX A — TERMS OF REFERENCE — BOARD OF DIRECTORS
Role and Responsibilities
The principal role of the Board of Directors (the “Board”) is stewardship of the Corporation with the creation of shareholder value, including the protection and enhancement of the value of its assets, as the fundamental objective. The stewardship responsibility means that the Board oversees the conduct of the business and management, which is responsible for the day-to-day conduct of the business. The Board must assess and ensure systems are in place to manage the risks of the Corporation’s business with the objective of preserving the Corporation’s assets. The Board, through senior management of the Corporation, sets the attitude and disposition of the Corporation towards compliance with applicable laws, environmental, safety and health policies, financial practices and reporting. In addition to its primary accountability to its shareholder, the Board is also accountable to employees, government authorities and other stakeholders.
Composition
The Board of Directors is elected annually by the Corporation’s shareholder and consists of that number of Directors, as determined from time to time by the Corporation’s shareholder. The number of Directors to be elected is currently set at nine. While the election of directors is ultimately determined by the Corporation’s shareholder, it is the policy of the Board that at least three Directors be independent (as defined under applicable securities laws).
The Chairman of the Board presides as Chair at all meetings of the Board. In the event the Chairman of the Board is unable to attend a meeting, the Vice-Chairman and CEO shall preside as Chair. In the absence of the Chairman of the Board and the Vice-Chairman and CEO, the Vice-Chairman, or any other director shall preside as Chair of a meeting. The Corporate Secretary or, in the absence of the Corporate Secretary, an Assistant Corporate Secretary an officer or employee of the Corporation, attends all meetings of the Board and records the proceedings thereof. The Corporate Secretary prepares and keeps minutes and records of all meetings of the Board.
Meetings
Meetings of the Board of Directors, including telephone conference meetings, are to be held at such time and place as the Chairman of the Board or a majority of the Directors may determine. Notice of meetings shall be given to each Director not less than 48 hours before the time of the meeting. Meetings of the Board of Directors may be held without formal notice if all of the Directors are present and do not object to notice not having been given, or if those absent waive notice in any manner before or after the meeting. In addition, each newly elected Board may, without notice, hold its first meeting immediately following the meeting or resolution of shareholders at which such Board was elected.
Notice of meeting will be given in writing and may be delivered personally, given by mail, facsimile or other electronic communication and need not be accompanied by an agenda or any other material. The notice shall however specify the purpose or purposes for which the meeting is being held.
Subject to the requirements of the Canada Business Corporations Act requiring resident Canadian directors to be present at any meeting of the Board, fifty percent (50%) of the directors then in office and in attendance shall constitute a quorum for the transaction of business at any meeting of the Board. No business may be transacted by the Board of Directors except at a meeting of its members at which a quorum of the Board of Directors is present.
Each Board member is expected to attend Board meetings and meetings of committees of which he or she is a member and to become familiar with deliberations and decisions as soon as possible after any missed meetings. In that regard, members of the Board are expected to prepare for Board (and committee) meetings by reviewing meeting materials distributed to members of the Board, to the extent feasible, in advance of such meetings. Matters of a confidential or sensitive nature may be discussed at Board (or committee) meetings without advance distribution of meeting materials to members of the Board. It is expected that members of the Board will actively participate in Board meetings.
The independent Directors shall have the opportunity to hold separate in camera discussions upon completion of all meetings of the Board.
A resolution in writing signed by all the Directors entitled to vote on that resolution at a meeting of the Directors is as valid as if it had been passed at a meeting of the Directors. A copy of any such resolution in writing is kept with the minutes of the proceedings of the Directors.
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At meetings of the Board, any matter requiring a resolution of the Directors is decided by a majority of the votes cast on the question.
Amendments
No alteration to the roles and responsibilities of the Board of Directors shall be effective without the approval of the Board of Directors.
The Board of Directors shall review the adequacy of these Terms of Reference and that of its Committees on an annual basis.
Compensation
Only non-employee Directors shall receive remuneration for their service as Directors.
Non-Delegable Responsibilities
Pursuant to the Canada Business Corporations Act (the “Act”), various matters are considered of such importance so as to warrant the attention of all Directors and, accordingly, the Act prescribes that such matters either cannot be delegated or may only be delegated in a qualified or partial manner:
1. the submission of items to the Corporation’s shareholder or ultimate shareholder for its approval;
2. the filling of a vacancy among the directors or in the office of the external auditor;
3. the appointment of additional directors;
4. the issue of securities;
5. the declaration of dividends;
6. the purchase, redemption or other acquisition of the Corporation’s own shares;
7. the payment of certain commissions prescribed by the Act;
8. the approval of annual financial statements; and
9. the adoption, amendment or repeal of by-laws.
Primary Responsibilities
The principal responsibilities of the Board required to ensure the overall stewardship of the Corporation are as follows:
1. the Board must approve, on an annual basis, the Corporation’s business and financial plans, as well as the annual capital expenditure programs which take into account, among other things, the opportunities and risks of the Corporation’s business;
2. the Board must ensure that processes are in place to enable it to monitor and measure management’s performance in achieving the Corporation’s stated objectives.
3. the Board shall satisfy itself as to the business and professional integrity of the executive officers and that the executive officers create a culture of integrity throughout the Corporation;
4. the Board must ensure that the necessary internal controls and management systems are in place that effectively monitor the Corporation’s operations and ensure compliance with applicable laws, regulations and policies;
5. the Board must monitor compliance with the Corporation’s Code of Business Conduct and Ethics;
6. the Board must ensure that processes are in place to properly oversee Corporation sponsored pension plans; and
7. the Board must ensure that the Corporation has appropriate processes in place to effectively communicate with employees, government authorities and other stakeholders.
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Typical Board Matters
The following is not an exhaustive list but typifies matters generally considered by the Board in fulfilling its responsibility for stewardship of the Corporation. The Board may determine it appropriate to delegate certain of these matters to committees of the Board:
1. appointment of executive officers;
2. considering the appropriate size of the Board, with a view to facilitating effective decision-making;
3. determining the number of directors and recommending nominees for election by the shareholder;
4. adopting a process to consider and assess the competencies and skills of each Board member and the Board as a whole;
5. determining the remuneration of directors and external auditors;
6. reviewing and recommending to its shareholder, changes to capital structure;
7. overseeing the overall health, safety, and environmental (“HSE”) performance of the Corporation, the Corporation’s risk management and strategies with respect to HSE and monitoring the tactical systems and processes that support the HSE strategies;
8. approving banking, borrowing and investment policies;
9. approving ethics policies or other corporate policies consistent with that of its ultimate shareholder;
10. determining dividend policy;
11. developing the Corporation’s approach to corporate governance including, without limitation, developing a set of corporate governance principles and guidelines;
12. appointing members to committees of the Board of Directors and approving terms of reference for and the matters to be delegated to such committees;
13. granting any waivers from the Corporation’s Policy on Business Conduct and Ethics for the benefit of the Corporation’s directors or executive officers;
14. granting and delegating authority to designated officers and employees including the authority to commit capital, open bank accounts, sign bank requisitions and sign contracts, documents and instruments in writing;
15. approving the funding policy for the Corporation’s defined benefit pension plans, including decisions related to surplus withdrawals and contribution holidays;
16. reviewing and approving amendments to the terms and conditions of the registered and non-registered pension plans maintained by the Company (other than amendment that are of an administrative nature, which are within the purview of Human Resources), including ad hoc adjustments to pensions, and to consider any proposals submitted by management for the amendment of these plans; and
17. approving the acquisition or disposition of certain corporate assets.
Reserves Data And Other Oil And Gas Information
The Board shall:
1. annually consider whether the involvement of an independent “Qualified Reserves Evaluator/Auditor” is necessary to achieve the desired quality and reliability of reserves data disclosure. The Board shall review management’s appointment of one or more Qualified Reserves Evaluator/Auditors, whether independent or not. In the case of any proposed change in such appointment, the Board shall determine the reasons for the proposal and whether there have been disputes between the Qualified Reserves Evaluator/Auditor and management;
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2. review, with reasonable frequency, the Company’s procedures relating to the disclosure of information with respect to oil and gas activities, including its procedures for complying with applicable disclosure requirements and restrictions contained in National Instrument 51-101 (“NI 51-101”);
3. review, with reasonable frequency, the Company’s procedures for providing information to the Qualified Reserves Evaluator/Auditor who reports on reserves data;
4. meet with management and the Qualified Reserves Evaluator/Auditor to:
(a) determine whether any restrictions affect the ability of the Qualified Reserves Evaluator/Auditor to report on reserves data without reservation; and
(b) review the reserves data and the report of the Qualified Reserves Evaluator/Auditor; and
5. as required by applicable law, review and approve:
(a) the content and filing of the Company’s statements of reserves data and other information required by Form 1 of NI 51-101;
(b) the filing of reports of the Qualified Reserves Evaluator/Auditor on Form 2 of NI 51-101; and
(c) the content and filing of reports of management and Directors on Form 3 of NI 51-101;
The Qualified Reserves Evaluator/Auditor shall have access to the Board of Directors. Meetings with the Qualified Reserves Evaluator/Auditor may be held separately, as requested by the Board of Directors.
Board Committees
The Board of Directors has the authority to appoint a committee or committees of the Board and may delegate powers to such committees (with the exceptions prescribed by the Act). The matters to be delegated to committees of the Board and the constitution of such committees are assessed annually or more frequently as circumstances require. The following committees are ordinarily constituted:
1. the Audit Committee, to deal with financial reporting and control systems.
Pension Management Committee
The Board of Directors has the authority to establish a Pension Management Committee, comprised of officers of the Corporation, to deal with employee pension plans and related matters and may delegate powers to such committee (with the exceptions prescribed by the Act). The members of the Pension Management Committee will be appointed following a recommendation from the Corporation’s shareholder. The matters to be delegated to the Pension Management Committee and the constitution of such committee are assessed annually or more frequently as circumstances require.
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SCHEDULE D — EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
This Compensation Discussion & Analysis (“CD&A”) describes ROGCI’s executive compensation programs and overall approach to executive compensation. The former President and Chief Executive Officer, as well as three former Executive Vice-Presidents, qualify as NEOs (as defined below) and these four individuals are collectively referred to herein as “Former Executive Officers”. The current Chief Executive Officer, Executive Director, North America, and Senior Vice President, Finance, Treasurer and Chief Financial Officer are collectively referred to herein as “Executive Officers”. Specifically discussed in the CD&A is the compensation for the following Named Executive Officers (“NEOs”):
· Luis Cabra Dueñas, Chief Executive Officer (“CEO”);
· John Rossall, Executive Director, North America;
· David Newby, Senior Vice President, Finance, Treasurer and Chief Financial Officer;
· Harold N. Kvisle, former President and Chief Executive Officer;
· Paul R. Smith, former Executive Vice-President, Finance and Chief Financial Officer;
· A. Paul Blakeley, former Executive Vice-President, Asia Pacific; and
· Paul C. Warwick, former Executive Vice-President, Europe & Atlantic.
For the purposes of this CD&A, “executive compensation” means base salary, short-term and long-term incentives, benefits (including post-employment benefits and change of control provisions), and other compensation, which are all reported in Canadian dollars. The executive compensation program covers all executive positions that report to the CEO.
Mr. Cabra’s compensation details have not been disclosed in this document, as he is not paid directly by ROGCI. Mr. Cabra also serves as Executive Managing Director, of Exploration and Production of Repsol and as such, his compensation is derived through Repsol and its compensation schemes, goals and objectives, which in turn are tied to Repsol performance.
Compensation Philosophy and Program Design
ROGCI’s executive compensation philosophy is intended to reward Executive Officers commensurate with the success of the Company, their region or functional area, execution of the strategy, personal achievements in support of that strategy and for acting in accordance with ROGCI’s values.
In keeping with this philosophy, the main objectives of ROGCI’s executive compensation programs are to:
· Pay for performance by rewarding the attainment of goals and objectives;
· Attract, retain and motivate high quality Executive Officers to drive organizational success, with appropriate consideration of risk by complying with the legal, regulatory and corporate obligations of the Company; and
· To encourage all Executive Officers to act in the best interests of the Company.
Through goal setting and performance reviews Executive Officers have a clear line of sight between individual contributions, organizational success, and the impact on compensation.
Executive Officers have both fixed and performance-based elements of compensation.
Annual Compensation Review Process
Compensation for the Executive Officers is reviewed on an annual basis, and involves a detailed review of corporate, regional/ functional, and individual performance, as well as market compensation data. The CEO reviews base salaries, variable pay and long-term incentives. Compensation is reviewed individually and as a whole (that is, “total direct compensation” is considered in its entirety).
The ROGCI Board reviews and approves compensation for all Executive Officers with recommendations from Repsol as the Company’s ultimate shareholder. Similarly, the ROGCI Board will approve any long-term incentive plans applicable to ROGCI Executive Officers and review all proposed grants thereunder for the benefit of Executive Officers.
REPSOL OIL & GAS CANADA INC. ANNUAL INFORMATION FORM 2015
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Competitive Market Analysis
Mr. Rossall and Mr. Newby’s total direct compensation has been benchmarked to positions with responsibilities similar to their current roles through consideration of the P50 and P75 market reference points at Canadian energy companies. This has been done using a variety of different revenue and production level data cuts run from a proprietary compensation database purchased from a third party compensation survey provider and provided to the Company on an aggregate basis. Given the confidential nature of the data, the third party compensation survey provider cannot provide specific company names.
Executive Compensation Consultants
In 2015, there were no services provided by executive compensation consultants.
In 2014, Hugessen Consulting (“Hugessen”) was retained to provide an independent external opinion on various executive compensation matters, and advice to ROGCI’s HRC (as hereinafter defined) in respect of compensation for ROGCI’s executives.
Executive Compensation Related Fees
Consultant | | Type of Work | | Fees paid ($)
2015 | | Fees paid ($)
2014 | |
Hugessen | | Consulting support to the Board, the HRC, or the HRC Chair on compensation matters | | $ | 0 | | $ | 340,982 | |
| | | | | | | | | |
Determining Executive Officer Compensation — Context for Decision-Making
Executive compensation is linked to ROGCI’s total Company performance against both strategic and operating targets.
The program is designed so that overall corporate results, regional/functional results, as well as each Executive Officer’s individual performance, influence the final determination of executive compensation. For Mr. Rossall, North American regional performance is considered and for Mr. Newby, ROGCI’s total Company performance is considered as the regional/functional component of their performance. Market data is also considered in determining executive compensation levels for Executive Officers. Finally, while the majority of the executive compensation program is tied to quantitative measures, there is always an element of informed judgment that is applied in determining pay outcomes.
Due to the change of control that resulted in ROGCI’s compensation programs to be under review, the ROGCI Board did not conduct a risk assessment in 2015.
The 2015 performance agreements of the Executive Officers have four main components:
· Minimum total Company requirements
· Key operational targets
· Value creation
· Strategic initiatives
Strategic initiatives include initiatives to drive development and execution of the long-term strategy and create shareholder value. Minimum total Company requirements include tangible benchmarks for evaluating performance in terms of safety, legal and regulatory compliance, organization and internal processes and implementing a culture of continuous improvement and operational excellence. This metric is used as a mechanism for applying downward discretion when ROGCI does not meet its minimum standards in these areas.
Safety is a top priority of the Company, and safety metrics apply to ROGCI employees, contractors and all others directly affected by ROGCI’s operations. Safety goals are included under “minimum total Company requirements” to ensure that the Company’s safety culture is driven by a visible commitment by Executive Officers.
The CEO considers the targets included in the performance agreements when evaluating performance and determining the variable component of compensation. Performance against these targets is then supplemented by a thorough assessment of all
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business and individual performance results and a qualitative evaluation of strategic leadership. The broader economic environment in which the business is operating, the degree to which risk mitigation informed the decisions made by Executive Officers, and the performance of management in ensuring that the Company acts in a socially responsible manner are also considered.
The CEO finalizes recommendations on all executive compensation elements at the same time that the annual financial results are reviewed and they are then reviewed and approved by the ROGCI Board. This ensures that a holistic view of performance and compensation is taken.
Hedging
In 2012, the ROGCI Board approved an amendment to ROGCI’s Insider Trading Policy that prohibits reporting insiders from purchasing financial instruments designed to hedge or offset a decrease in market value of equity securities granted as compensation or other ROGCI securities which are held, directly or indirectly, by the reporting insider. No Executive Officer or director has entered into any such arrangements.
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Executive Compensation Elements
Base salary and variable pay reward both Company and individual Executive Officer performance on an annual basis. The long-term incentive program is currently under review, but is intended to reward Executive Officers for long-term performance of the Company.
The summary chart below describes the key objectives for each executive compensation element. The sections that follow describe these elements in further detail.
Base Salary
Base salary provides a fixed level of income to Executive Officers. When making base salary decisions, an Executive Officer’s skills, relevant experience, level of contribution to the Company, and overall performance is assessed. Base salaries for Executive Officers are reviewed annually and if applicable, adjustments are made in early April of each year.
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Variable Pay Plan
Variable pay is a key element of executive compensation and provides a target total cash compensation opportunity at a market competitive level. The Variable Pay Plan (“VPP”) is designed to link an Executive Officer’s individual performance and impact on total Company performance to actual variable pay received. ROGCI’s Executive Officers share in the risks and rewards of safety, environmental, operational, financial, people and strategic objectives.
Variable pay opportunities for 2015 range from 0% to 200% of target for each of the total Company, regional/functional and individual components of the program. Variable pay in respect of the current year’s performance is paid in April of the following year after a full assessment by the CEO.
In 2015, the first half of the 2015 annual variable pay was paid in advance in September 2015 to employees using a conservative approach for the determination of mid-year multipliers and mid-year payout calculations. As such, the mid-year annual variable pay was based on a corporate and regional/functional multiplier of 0.8 and an individual multiplier of 1.0. The total 2015 annual variable pay is based on the full year approved corporate, regional/functional and individual performance multipliers. The final payment is calculated net of the mid-year payment, and will be paid in 2016.
The variable pay targets, opportunity ranges, and relative weightings for the Executive Officers were as follows:
| | 2015 Variable Pay | | 2015 Weighting on Results | |
Position | | Target
(as a % of
salary earnings) | | Opportunity
Range
(as a % of
salary earnings) | | Corporate1 | | Region/
Functional Area2 | | Individual | |
Chief Executive Officer | | n/a | | n/a | | n/a | | n/a | | n/a | |
Executive Director, North America. | | 45 | | 0 – 90 | | 22.5 | | 22.5 | | 55 | |
SVP, Finance, Treasurer and Chief Financial Officer | | 45 | | 0 – 90 | | 22.5 | | 22.5 | | 55 | |
(1) Corporate is based on ROGCI 2015 performance.
(2) By design, Mr. Rossall’s region is comprised of the combined legacy Repsol and ROGCI North America exploration and production operations and Mr. Newby’s region as a corporate employee is defined as all of ROGCI on a consolidated basis.
2015 Variable Pay Plan Award
As noted under the heading “Determining Executive Officer Compensation — Context for Decision-Making”, the CEO considers market data, the performance of the Company as a whole against the targets set out in the Executive Officers’ performance agreements, and the broader environment in which the Company operates in making his recommendation to the ROGCI Board on VPP awards. Acting in the best interests of the Company and with recommendations from the Company’s ultimate shareholder, the CEO has the ability to adjust recommendations for variable pay upward or downward based on his judgment of these factors.
In February 2016, the CEO, as well as the ROGCI Board, considered the performance agreements of the Executive Officers against actual results achieved. The following observations with respect to the corporate objectives for 2015 were made:
Corporate Objectives and 2015 results
2015 objectives | | 2015 results |
Minimum Total Company Requirements | | Board overall assessment: Below expectations |
Health Safety and Environment (HSE) · Continue to strengthen HSE leadership and authority at the front lines · Demonstrate top-quartile OGP(1) HSE performance through · Reduce LTIF(2) by 53% from 2014 · Reduce TRIF(3) by 16% from 2014 · Reduce spill frequency by 8% from 2014 · Zero administrative orders and judicial actions | | · Continued to implement Global Standard for Safe Operations and reinforcement of front-line leadership and authority for delivery of safe operations · Missed TRIF, LTIF, and Spill reduction targets · Zero administrative orders or judicial actions achieved |
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2015 objectives | | 2015 results |
Legal, Regulatory and Corporate Obligations · Meet all legal obligations and comply with all regulatory and compliance obligations through efficient business process | | · Complied with all material legal and regulatory obligations |
People, Organization and Internal Processes · Restructure the corporate and regional organizations in anticipation of full integration with Repsol · Implement a consistent Operational Excellence and Leadership model across ROGCI | | · Corporate and regional organizations resized to correspond to reduced workloads in a weak commodity price environment, and to harness synergies from the Repsol integration · Operational Excellence model deployed across ROGCI |
Business Processes · Drive top quartile cost-competitiveness through business process improvements across ROGCI · Improve the quality and focus of business plans, performance agreements and performance feedback · Participate constructively in the Repsol/ROGCI integration process, in anticipation of a Q2 2015 closing | | · Transaction successfully closed in May, with integration into Repsol progressing well-processes continuing to be redefined with synergies identified and attained · Significant cost reductions delivered during 2015-cost efficiency effort rolled out across the organization |
Key Operational Targets | | Board overall assessment: Exceeded expectations |
· Total production(4) of 372mboe/d · Total operating, transportation and net G&A(5) costs of US$2.5 billion · Non-GAAP cash flow(6) of US$1.3 billion · Total E&D(7) spending of US$2.3 billion | | · 372 mboe/d produced · Total costs of US$2.1 billion · Non-GAAP cash flow of US$2.3 billion · Total E&D spending of US$1.6 billion · Operational performance results were impacted by the sale of the Company’s Norwegian subsidiary to Repsol in September not accounted for in operational targets |
Value Creation | | Board overall assessment: Exceeded expectations |
Live within our means and focus our capital expenditures | | · Closed agreement with Statoil to sell a net 13% working interest in the Eagle Ford, reducing near-term capital obligations · Reached agreement to transfer Block CPE-6 working interest to partner(8), allowing for capital to be focused on higher-grade near-term opportunities in Colombia |
Practice Operational Excellence | | · Continued progress on driving HSE accountability to the front lines · Continued progress on reducing drilling and completion costs and cycle times across North American business · Intervention at Montrose Area Redevelopment making good progress · Technical functions restructured to provide technical expertise and assurance · UKJV Business Improvement Plan recommendations accepted and implemented |
Demonstrate quality decisions and risk management | | · Enterprise risk framework implemented throughout ROGCI |
Strategic Initiatives | | Board overall assessment: Exceeded expectations |
Gain all necessary approvals for the Repsol Transaction and ensure ROGCI compliance with the Arrangement Agreement | | · Received all necessary approvals from shareholders and governments to progress transaction · Integrated ROGCI operations and personnel to Repsol management hierarchy upon closing transaction |
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2015 objectives | | 2015 results |
Tightly manage all costs in a weak commodity price environment | | · Used aggressive supply chain renegotiations and front-line cost control to lower service and operating costs in all regions |
Deliver an effective transition and integration process | | · Progressed top-down organizational review to maximize Repsol’s ability to integrate ROGCI personnel post-closing · Name of the Company was legally changed to Repsol Oil & Gas Canada Inc. on January 1, 2016 · Absorption of legacy ROGCI groups into one singular Repsol organization ongoing |
Maintain balance sheet strength and deliver strong core regions to Repsol through closing | | · Retained investment grade credit rating through closing · Continued to build competitive advantage in core areas |
(1) International Association of Oil and Gas Producers
(2) Lost Time Injury Frequency
(3) Total Recordable Injury Frequency
(4) A boe conversion ratio of 5.615mcf:1bbl is assumed in this context.
(5) General and Administrative
(6) In this table, as well as the following performance contract tables, cash flow—as commonly used in the oil and gas industry—represents net income before exploration costs, DD&A, deferred taxes and other non-cash expenses including the Company’s share of cash flow from equity accounted entities. Cash flow is used by the Company to assess operating results between years and between peer companies using different accounting policies. Cash flow is not a measure defined by IFRS.
(7) In this table, as well as the following performance contract tables, exploration and development (E&D) spending is calculated by adjusting the exploration and development expenditure per the financial statements for exploration costs that were expensed as incurred.
(8) Subject to regulatory approval.
2015 Corporate Multiplier and Key Determinants
Based on the CEO’s assessment of Company performance in 2015, the ROGCI Board approved a corporate multiplier of 1.0 for the 2015 performance year. Consideration was given to the delivery of operating performance targets in a rapidly deteriorating economic context, successfully closing the purchase transaction with Repsol in May, and furtherance of realizing cost reductions and transaction synergies through the rest of the year, which was offset by safety performance that was below expectations. The determination of the outcome and score for each category are highlighted in the table below:
2015 Objectives | | Weightings (%) | | Range1 | | Outcome | | Score |
Minimum Total Company Requirements · HSE performance targets not met despite ongoing trend of continuous improvement · Complied with all material legal and regulatory obligations | | Applied as multiplier | | 0%-100% | | Below expectations | | 0.8 |
Key Operational Targets2 · Production delivery on target · Operating costs executed 16% below target · Capital program executed 30% below target | | 50% | | 50%-150% | | Exceeded Expectations | | 1.3 |
Value Creation · Reached agreement with various partners to reconfigure participation in CPE-6 in Colombia and Eagle Ford in USA | | 25% | | 50%-150% | | Exceeded Expectations | | 1.2 |
Strategic Initiatives · Deployed divestment proceeds to short term debt service and improving balance sheet strength · Closed Repsol Transaction successfully in May 2015 | | 25% | | 50%-150% | | Exceeded Expectations | | 1.2 |
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(1) Combining the minimum possible scores in each range results in a formulaic minimum score of 0%; combining the maximum possible score in each range results in a formulaic maximum score of 150%. However, the Board may apply discretion in situations with exceptionally strong or poor performance, and in such cases, the final score can range 0%-200% of target.
(2) Targets and results not normalized for results of Norway disposition.
The final score was calculated by adding together the scores for operating performance, value creation and strategic initiatives weighted by a 50%, 25% and 25% weighting respectively, then multiplying this result by the minimum requirements’ score.
Executive Officers’ Performance and Compensation
John Rossall
Executive Director, North America
Mr. Rossall joined the Company in November, 2011 and is currently Executive Director, North America. For 2015, Mr. Rossall was responsible for the day-to-day operations of the Canadian Business Unit for ROGCI until the change of control on May 8, 2015 and the North America Business Unit for both ROGCI and Repsol S.A. following May 8, 2015, but does not oversee the remainder of the ROGCI perimeter assets.
The ROGCI Board, at the recommendation of the CEO, approved a North America regional performance score of 1.0 to acknowledge strong production, operating and capital expense performance that was offset by safety performance that was below expectations. Based on Mr. Rossall’s leadership through the integration and his positive impacts on global E&P initiatives, Mr. Rossall received an individual performance score of 1.2. Combining these outcomes with the corporate score of 1.0, and applying the corporate/regional/individual weightings of 22.5%/22.5%/55% resulted in a final VPP multiplier of 1.11 for Mr. Rossall. Applying this performance multiplier to Mr. Rossall’s VPP target of 45% of salary resulted in a ROGCI bonus of $249,267.
David Newby
Senior Vice President, Finance, Treasurer and Chief Financial Officer
Mr. Newby joined the Company in 2010 as Vice President International Finance and in the intervening years has expanded his role progressively taking on Global Finance, Treasury and the Chief Financial Officer role. For 2015, Mr. Newby was responsible for the finance, accounting and tax accounting functions of ROGCI.
Mr. Newby’s employment will end in 2016. As a result, his 2015 VPP will be paid at target in accordance with the terms of his employment contract.
Long-Term Incentives
There were grants made in 2015 under the Executive Deferred Share Unit plan (the “EDSU Plan”) to Mr. Kvisle as part of his standard compensation program. The EDSU plan was terminated in 2015 on closing of the Repsol Transaction and all outstanding defined share units issued under the EDSU plan were settled in accordance with the terms of the plan. None of the other Former Executive Officers or Executive Officers received a grant in 2015 under any other long-term incentive plan.
The long-term incentive program is currently under review and none of the Executive Officers currently hold any ROGCI long-term incentives.
Stock Options (Option-Based Awards)
The Company did not grant stock options to any Executive Officers or directors in 2015. All stock option plans previously outstanding were terminated in 2015 as part of the Repsol Transaction.
Performance Share Units (Share-Based Awards)
Overview
The Performance Share Unit (“PSU”) plan, which was terminated in 2015 on closing of the Repsol Transaction, was strictly performance-based and intended to reward Executive Officers for the Company’s performance against specific corporate goals and objectives.
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PSUs were a notional share equivalent based on the value of the Company’s underlying Common Shares. PSUs were evaluated over a three-year performance cycle, and the number of PSUs that vested following the three-year performance cycle was subject to the Company’s achievements against predetermined performance targets. The vesting performance factor could range from 0%-150% for the 2012 grant and 0%-200% for the 2013 and 2014 grants, and the vested PSUs were settled after tax in the form of the Company’s Common Shares, which were purchased by the Company on the open market. Participants in the PSU plan were credited with additional PSUs corresponding to any associated dividend payments (referred to as “dividend equivalent PSUs”).
Assessment of the 2012 PSU Grant
At the conclusion of the 2012 performance year, ROGCI’s Human Resources Committee (“HRC”) determined the metrics that were set at the time of grant for the 2012 PSU grant were no longer aligned with the new strategic direction of the Company. For Former Executive Officers (as defined above) with this grant, past performance (prior to December 31, 2012) was crystallized at a performance multiple of 18%, representing one-third of the three-year performance period, and future performance (after December 31, 2012) was measured against revised metrics that were aligned with the new strategy. This approach was adopted to provide appropriate compensation for the completed portions of the awards, while ensuring that the compensation program for continuing Former Executive Officers continued to be aligned with the Company’s new priorities.
The remaining two-thirds of the 2012 PSU grant vested for Former Executive Officers based on performance against the annual total Company performance metrics for the 2013 and 2014 performance years. The final total Company performance score in each of 2013 and 2014 was 100%. Combining the score of 18% for the first year of this grant, with the score of 100% for each of the final two years of this grant, resulted in a calculated performance score of 73%. As negotiated with Repsol, the HRC then applied discretion to increase the final score to 100% for the Former Executive Officers.
For current Executive Officers, the 2012 PSU grant vested with a final score of 31% based on the prior three year results against the total Company performance metrics but a minimum 75% floor was to be applied. As negotiated with Repsol, the HRC then applied discretion to increase the final score to 100% for the current Executive Officers. These terms were consistent with what was provided to all employees who were not executives at the time of the 2012 grant.
Payout of the 2013 and 2014 PSU Grant
Under the terms of the Plan of Arrangement governing the Repsol Transaction, the unvested 2013 and 2014 PSU grants have paid out at their target of 100%.
Restricted Share Units (Share-Based Awards)
Overview
ROGCI had a senior employee Restricted Share Unit (“RSU”) plan, which was terminated in 2015 on closing of the Repsol Transaction, whereby the Company could approve grants of RSUs on a select basis to attract and/or retain senior employees with the knowledge, experience and expertise required by the Company. The RSU plan was not an annual component of an Executive Officer’s compensation package.
RSUs were notional share equivalents with the value of the Company’s underlying Common Shares and they fully vested after three years from the grant date. Under the plan, participants were also credited with additional RSUs corresponding to any associated notional dividend payments (referred to as “dividend equivalent RSUs”). RSUs were settled in cash at the end of the vesting period based on the fair market value, defined as the average of the closing prices of the Common Shares on the TSX over the previous five trading days, multiplied by the number of vested RSUs.
The RSU plan provides that, if an Executive Officer voluntarily resigned or was terminated for cause during the vesting period, the RSUs and any dividend equivalent RSUs would be cancelled and no payment would be made. In the event of a change of control prior to the end of the vesting period, all RSUs and dividend equivalent RSUs in respect thereof would vest on the date of such change of control. As a result of the Repsol Transaction, all outstanding RSUs (including those previously granted to Mr. Warwick) have fully vested.
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Global Restricted Share Units (Share-Based Awards)
Overview
ROGCI also had a Global Restricted Share Unit (“GRSU”) plan that was provided to all employees below the Executive Vice President level in 2013. The GRSU Plan was terminated in 2015 on closing of the Repsol Transaction.
Similar to RSUs, GRSUs were notional share equivalents with the value of the Company’s underlying Common Shares and settled the same way as RSUs, however, GRSUs vested one third each year over three years. Notional dividend payments also applied to GRSUs (referred to as “dividend equivalent GRSUs”).
The GRSU plan also had the same termination and change of control provisions as the RSU plan. The second third of the 2013 GRSU grant vested on April 1, 2015 for Mr. Rossall and Mr. Newby and the vesting of the final third was accelerated on the date of the change of control pursuant to the terms of the GRSU Plan.
Executive Deferred Share Units
Overview
In December 2011, the Company’s HRC approved the EDSU Plan to promote greater alignment of long-term interests between executives and shareholders of the Company, in a tax efficient manner, and to support executives in reaching their share ownership guidelines. This was achieved by allowing executives to choose to receive a portion of future variable pay plan awards (up to 100% of the award) in the form of deferred share units, which represented a notional investment in the Company’s Common Shares, rather than an immediate cash payment. There were no performance conditions applicable to these elective EDSUs.
The former Executive Officers’ December 2014 election applied towards their 2015 variable pay, with the grant of EDSUs pursuant to those elections to be made in April 2016. Mr. Kvisle elected to receive 100% of his variable pay plan awards in the form of EDSUs each year; to this end he had taken his variable pay payouts for the 2013 and 2014 performance years in the form of EDSUs, and would have taken the variable payout in respect to the 2015 performance year had there not been a change of control. Mr. Kvisle had also elected to receive 25% of his base salary, along with the value of some perquisite items that he would have otherwise received, in the form of EDSUs which were granted quarterly in arrears. Mr. Kvisle did not participate in the Company’s pension plan for executive officers, but instead received, on an annual basis, EDSUs of a value equal to the incremental compensatory value he would have accrued had he participated in the executive pension plan.
Mr. Kvisle received grants of EDSUs in 2015 in lieu of his 2015 salary and perquisites, 2014 variable pay and 2014 pension.
Following closing of the Repsol Transaction, all EDSUs have settled and paid out as cash in accordance with their terms. The EDSU Plan was also terminated on closing of the Repsol Transaction.
Performance-Based Executive Deferred Share Units
Overview
Mr. Kvisle received his LTIP awards in the form of performance-based EDSUs. The performance-based EDSUs became eligible to vest based on an one-year performance period. Vesting eligibility was assessed by the Company based on performance in relation to the objectives set out in Mr. Kvisle’s annual performance agreement. Performance-based EDSUs that became eligible to vest in a particular year would be paid out at the later of:
i) the date when Mr. Kvisle ceased to be an employee of the Company; and
ii) the date when Mr. Kvisle ceased to be a director of the Company (if he continued as a member of the Board following his term as CEO).
Mr. Kvisle was subject to a post-retirement ownership requirement, where he was required to hold one Common Share for each vested performance-based EDSU that he received, up until the third anniversary of the date of grant date respective to that performance-based EDSU, net of taxes. This requirement was intended to ensure that each performance-based EDSU would track shareholder experience for at least three years from date of grant (this holding requirement became irrelevant on the date of the change of control as a wholly owned subsidiary of Repsol acquired all outstanding shares of the Company.)
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Performance-based EDSUs that were deemed by the HRC to be ineligible to vest, following their one-year performance period, were forfeited and cancelled. The vesting performance factor for performance-based EDSUs could range from 50%-150% of the number of performance-based EDSUs granted.
Following the change of control with Repsol, all performance-based EDSUs have settled and paid out as cash in accordance with their terms.
Retention Awards
In order to retain Mr. Rossall and Mr. Newby following the transaction, fixed cash retention awards were provided. Mr. Newby was provided with a cash retention amount payable upon termination. Mr. Rossall was provided a retention award that will pay out in 2016 and 2017.
Benefits, Savings and Pension
The Executive Officers are eligible for a benefits program offering the flexibility of making and managing their own benefit choices and creating a personal benefits program that meets their unique lifestyle requirements. Under the flexible benefit program, the Company provides a pool of flex credits to be used to purchase compulsory, supplemental and optional benefits, including life insurance, accidental death and dismemberment, long-term disability, supplementary medical and dental, contributions to the Company’s savings plan or to a health spending account. They may also contribute 5% of their annual base salary and variable pay to ROGCI’s savings plan, and contributions are then matched by the Company in the form of additional flex credits. Prior to the acquisition of the Company by Repsol, employee contributions into the Company’s savings plan, up to 5% of base salary and variable pay, had to be invested in the Company’s Common Shares. Upon closing of the Repsol Transaction, the proceeds of all Company Common Shares held under the saving plan were deposited into a money market fund. Following the closing of the transaction, all employee contributions can be invested in any investment fund available under the savings plan. Any unused flex credits are paid in cash as taxable earnings. Executive Officers are also eligible to participate in a contributory defined contribution pension plan.
Perquisites
Executive Officers are eligible to receive personal benefits which are not generally available to all employees. Perquisites include company parking, a corporate membership, financial services and a vehicle allowance, which remain reasonable and competitive with market practices. While perquisites generally comprise a relatively small percentage of overall total compensation, it is a prevalent market practice to maintain some level of perquisites.
Termination and Change of Control Benefits
Employment contracts contain change of control and termination provisions designed to retain Executive Officers in certain circumstances and promote continuity of management. Employment contracts allow for the payout of severance benefits to an Executive Officer if his or her employment is terminated within one year following the occurrence of specified events. The practice of including change of control provisions in executive employment contracts is consistent with industry peers and is influential in attracting and retaining executive talent. Refer to the heading “Employment Contracts and Termination” for more details.
Effective January 1, 2012, executive contracts for newly hired Executive Officers were revised to require termination of employment by the Company following a change of control (“double-trigger”) for termination benefits to become payable. The revised contract also includes non-competition and non-solicitation provisions as well as an intellectual property provision.
EXECUTIVE COMPENSATION TABLES
The following executive compensation tables summarize, for the periods indicated, the compensation of the Former Executive Officers and the Executive Officers. Collectively, these individuals are referred to in this section as the Named Executive Officers (“NEOs”). Figures are reported in Canadian dollars unless otherwise specified.
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Summary Compensation Table
The following table contains the compensation provided to NEOs during the year in which it was earned. Cash compensation is valued at the time that it was paid, long-term incentive compensation is valued at the time that it was granted, and pension amounts are valued at their present value.
Values shown in Canadian Dollars
Named Executive
Officers | | Year | | Salary
($) | | Share-Based
Awards2
($) | | Option-
Based
Awards3
($) | | Non-Equity
Annual
Incentive Plan
Compensation4
($) | | Non-Equity
Non-Annual
Incentive Plan
Compensation5
($) | | Pension
Value6
($) | | All Other
Compensation7
($) | | Total
Compensation
($) | |
Luis Cabra Dueñas 1 | | 2015 | | — | | — | | — | | — | | — | | — | | — | | — | |
Chief Executive Officer | | 2014 | | — | | — | | — | | — | | — | | — | | — | | — | |
| | 2013 | | — | �� | — | | — | | — | | — | | — | | — | | — | |
| | | | | | | | | | | | | | | | | | | |
John Rossall | | 2015 | | 499,033 | | — | | — | | 249,267 | | 2,400,000 | | 33,845 | | 58,757 | | 3,240,902 | |
Executive Director, North America | | 2014 | | 418,180 | | 650,005 | | — | | 252,650 | | — | | 21,443 | | 39,773 | | 1,382,051 | |
| | 2013 | | 409,000 | | 1,084,967 | | 109,169 | | 235,772 | | — | | 16,840 | | 34,824 | | 1,890,572 | |
| | | | | | | | | | | | | | | | | | | |
David Newby | | 2015 | | 350,000 | | — | | — | | 157,500 | | 185,500 | | 29,655 | | 41,707 | | 764,362 | |
Senior Vice President, Finance, Treasurer and Chief Financial Officer | | 2014 | | 342,530 | | 556,500 | | — | | 178,474 | | — | | 19,677 | | 35,147 | | 1,132,328 | |
| 2013 | | 315,590 | | 438,120 | | — | | 149,394 | | — | | 17,318 | | 30,933 | | 951,355 | |
| | | | | | | | | | | | | | | | | | | |
Harold N. Kvisle8,9 | | 2015 | | 463,228 | | 5,001 | | — | | — | | — | | — | | 12,049,308 | | 12,517,536 | |
Former President and Chief Executive Officer | | 2014 | | 1,299,994 | | 7,166,196 | | — | | 1,430,000 | | — | | — | | 180,096 | | 10,076,286 | |
| | 2013 | | 1,299,996 | | 6,606,001 | | — | | 1,558,700 | | — | | — | | 78,822 | | 9,543,519 | |
| | | | | | | | | | | | | | | | | | | |
Paul R. Smith | | 2015 | | 243,902 | | — | | — | | — | | — | | 201,900 | | 3,137,916 | | 3,583,717 | |
Former Executive Vice-President, Finance and Chief Financial Officer | | 2014 | | 685,000 | | 2,260,499 | | — | | 1,042,188 | | — | | 451,900 | | 106,293 | | 4,545,879 | |
| 2013 | | 685,000 | | 2,260,506 | | — | | 1,213,289 | | — | | 642,300 | | 51,986 | | 4,853,081 | |
| | | | | | | | | | | | | | | | | | | |
A. Paul Blakeley | | 2015 | | 399,583 | | — | | — | | — | | — | | 1,148,500 | | 2,944,758 | | 4,492,841 | |
Former Executive Vice-President, Asia Pacific | | 2014 | | 685,000 | | 2,260,499 | | — | | 455,953 | | — | | 381,600 | | 1,017,045 | | 4,800,097 | |
| | 2013 | | 685,000 | | 2,260,506 | | — | | 539,438 | | — | | 451,900 | | 836,891 | | 4,773,734 | |
| | | | | | | | | | | | | | | | | | | |
Paul C. Warwick10 | | 2015 | | 620,066 | | — | | — | | — | | — | | 2,336,800 | | 3,491,106 | | 6,447,973 | |
Former Executive Vice-President, Europe & Atlantic | | 2014 | | 785,627 | | 2,260,499 | | — | | 736,525 | | — | | 478,600 | | 98,797 | | 4,360,048 | |
| | 2013 | | 695,930 | | 2,260,506 | | — | | 587,191 | | — | | 410,000 | | 98,778 | | 4,052,404 | |
(1) Mr. Cabra is not compensated by ROGCI for his role as CEO of ROGCI, as such his compensation has not been disclosed.
(2) The grant date value of GRSU, PSU and performance-based EDSU awards is based on the number of units granted multiplied by the average closing price of the Company’s Common Shares on the TSX for the five days immediately prior to the grant date. For Mr. Rossall’s PSU award granted in 2013, a valuation ratio of 0.75 was applied in order to account for vesting restrictions and performance conditions attached to these grants; this valuation ratio was calculated by an independent consultant (Towers Watson) and was a commonly recognized way of calculating a meaningful and reasonable estimate of fair value.
Year
Reported | | Type of Grant | | NEO Recipients | | Grant Date | | Price | | Valuation
Factor | |
2014 | | performance-based EDSU | | Kvisle | | April 1, 2014 | | $ | 11.050 | | n/a | |
2014 | | PSU | | Rossall, Newby, Smith, Blakeley, Warwick | | April 1, 2014 | | $ | 11.050 | | n/a | |
2013 | | performance-based EDSU | | Kvisle | | April 1, 2013 | | $ | 12.314 | | n/a | |
2013 | | PSU | | Smith, Blakeley, Warwick | | April 1, 2013 | | $ | 12.314 | | n/a | |
2013 | | PSU | | Rossall | | February 21, 2013 | | $ | 12.620 | | 0.75 | |
2013 | | GRSU | | Rossall, Newby | | April 1, 2013 | | $ | 12.314 | | n/a | |
Share-based awards also include the value of EDSUs granted to Mr. Kvisle in lieu of the value of some perquisites he would have otherwise received; this EDSU grant is discussed in footnote 9 below.
For the purpose of accounting and financial statements, the Company values share-based awards as at the grant date by multiplying the share price by a forfeiture factor based on historical employee turnover. This is adjusted in subsequent periods based on the expected payout relative to target and amortized over the performance period. As such, the accounting fair value changes with each financial statement issued. As at May 8, 2015, the accounting fair value of share-based awards in 2015 to NEOs is $5,001.
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(3) Option-based award values reflect grant date fair market value using the Binomial Lattice Option Pricing Model; which is a commonly recognized way of calculating a meaningful and reasonable estimate of fair value. The grant date value of option-based awards is based on the number of units granted multiplied by the average of the prior day’s high and low price on the TSX multiplied by the binomial factor.
Year
Reported | | NEO
Recipients | | Grant Date | | Contractual
Term (years) | | Expected Life
(years) | | Volatility | | Yield | | Vesting | | Binomial
Factor | | Grant
Price | |
2013 | | Rossall | | February 21, 2013 | | 10 | | 6 | | 30.96 | % | 3.14 | % | 3 year, 1/3 p.a. | | 0.201 | | 12.625 | |
For the purposes of accounting and financial statements, the Company reports option awards as of the date of the financial statements and as such, the accounting fair value changes with each financial statement issued. There were no option-based awards granted to NEOs in 2015.
(4) Amounts shown are variable payments related to the performance year indicated, paid the following April.
· Mr. Newby’s employment will end in 2016. As a result, his 2015 VPP will be paid at target in accordance with the terms of his employment contract.
· For 2014, Mr. Kvisle elected to receive 100% of his VPP award in the form of EDSUs; these EDSUs were granted on April 1, 2015.
· For Mr. Smith, 2014 also includes a performance bonus paid in recognition of his contributions to the Company’s disposition program ($400,000), and 2013 also includes a performance bonus in recognition of his effectiveness in transitioning to the CFO role while continuing to assist the North America region ($600,000);
· For 2013, Messrs. Rossall and Kvisle elected to receive 50% and 100%, respectively, of their VPP awards in the form of EDSUs; these EDSUs were granted on April 1, 2014.
(5) Amounts shown are retention payments granted to Messrs. Rossall and Newby. Mr. Rossall will receive payments of $1,100,000 in 2016 and $1,300,000 in 2017 and Mr. Newby will receive a payment of $185,500 upon termination of employment in 2016.
(6) For Messrs. Rossall and Newby, represents the Company contributions to the defined contribution pension plans. For Messrs. Smith, Blakeley and Warwick, represents the current service cost plus the impact of other compensation-related items such as plan changes and pensionable earnings different than estimated, under the defined benefit pension plans.
(7) For Messrs. Kvisle, Smith, Blakeley and Warwick, amounts include the Company contributions to the savings plan, the premiums paid by the Company for life insurance, accidental death and dismemberment, medical, dental and long-term disability coverage, and any service awards. For Mr. Blakeley, amount includes costs attributable to his assignment in Asia; the costs are part of his relocation arrangement and are in line with ROGCI’s normal arrangements for expatriates. For Messrs. Rossall and Newby, amounts include the Company contributions to the savings plan, the value of the Company’s post-retirement benefits, the flex credits provided by the Company for life insurance, accidental death and dismemberment, medical, dental and long-term disability coverage, and any service awards. Any perquisites and other personal benefits have been excluded as they do not exceed the lesser of $50,000 or 10% of the total annual salary of the Executive Officer. For Messrs. Kvisle and Smith, amounts for 2014 also includes the value of an administrative correction granting EDSUs in lieu of missed savings plan contributions on the portion of variable pay that was taken in the form of EDSUs for the 2012 and 2013 performance years; these awards were made on April 1, 2014, at a share price of $11.05, with values of $95,485 and $18,509, respectively. For Mr. Kvisle, amounts for 2015 also include the value of an administrative correction in lieu of missed savings plan contributions on the portion of variable pay that was taken in the form of a cash amount of $72,941.
For Messrs. Kvisle, Smith, Blakeley and Warwick, 2015 amounts include termination payments (plus associated legal fees). Detailed information on the termination payments can be found in the table under the heading “Former Executive Officer Departure and Compensation”. For Mr. Kvisle who did not participate in the pension plan, the 2015 amount includes a cash payment of $3,732,800 representing the incremental value of pension benefits as of May 9, 2015 he would have received upon change of control had he participated in the defined benefit pension plans, as well as a payment of $836,300 in lieu of the compensatory value he would have received prior to change of control in 2015 had he participated in the defined benefit pension plans. For NEOs who received stock options, the incremental payment has been included as all of the option-based awards were cancelled at the closing of the Repsol Transaction on May 8, 2015 in exchange for $0.01 USD or CAD equivalent of $0.01204 per option as per outlined in the Arrangement Agreement.
(8) The amounts shown only reflect compensation payable to Mr. Kvisle as President and CEO of the Company. Prior to becoming the President and CEO on September 10, 2012, Mr. Kvisle received compensation for his service on the Company’s Board.
(9) Amounts for Mr. Kvisle include the following value of EDSUs granted:
· For 25% of his salary in 2013 ($324,996), 2014 ($324,994) and 2015 ($81,248) — these amounts have been reported as salary. In 2015, he received a cash payment of $34,821 in lieu of a prorated Q2 2015 salary EDSU grant which has been reported as salary;
· In lieu of the value of some perquisite items he otherwise would have received in 2013 ($20,006), 2014 ($19,993) and 2015 ($5,001) — these amounts have been reported as share-based awards. In 2015, he received a cash payment of $2,143 in lieu of a prorated Q2 2015 perquisite EDSU grant which has been reported as all other compensation; and
· In lieu of the compensatory value he would have received if he was participating in the pension plan in 2013 ($735,996) and 2014 ($1,296,200) — these amounts have been reported as share-based awards. In 2015, he received a cash payment of $836,300 in lieu of an EDSU grant due to the change of control which has been reported as all other compensation.
The grant date value of EDSU awards is based on the number of units granted multiplied by the average closing price of the Company’s Common Shares on the TSX for the five days immediately prior to the grant date.
| | | | In Lieu of Salary
(reported as salary) | | In Lieu of Perquisites
(reported as share-based awards) | | In Lieu of pension
(reported as share-based awards) | |
Year Reported | | Grant Date | | Units
Granted | | Price | | Value | | Units
Granted | | Price | | Value | | Units
Granted | | Price | | Value | |
2015 | | March 31, 2015 | | 8,465 | | 9.598 | | 81,247 | | 521 | | 9.598 | | 5,001 | | n/a | | n/a | | n/a | |
2014 | | March 31, 2015 | | n/a | | n/a | | n/a | | n/a | | n/a | | n/a | | 135,049 | | 9.598 | | 1,296,200 | |
2014 | | December 31, 2014 | | 8,929 | | 9.100 | | 81,254 | | 549 | | 9.100 | | 4,996 | | n/a | | n/a | | n/a | |
2014 | | September 30, 2014 | | 8,152 | | 9.966 | | 81,243 | | 502 | | 9.966 | | 5,003 | | n/a | | n/a | | n/a | |
2014 | | August 12, 2014 | | 7,102 | | 11.440 | | 81,247 | | 437 | | 11.440 | | 4,999 | | n/a | | n/a | | n/a | |
2014 | | April 1, 2014 | | 7,353 | | 11.050 | | 81,251 | | 452 | | 11.050 | | 4,995 | | n/a | | n/a | | n/a | |
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| | | | In Lieu of Salary
(reported as salary) | | In Lieu of Perquisites
(reported as share-based awards) | | In Lieu of pension
(reported as share-based awards) | |
Year Reported | | Grant Date | | Units
Granted | | Price | | Value | | Units
Granted | | Price | | Value | | Units
Granted | | Price | | Value | |
2013 | | February 21, 2014 | | n/a | | n/a | | n/a | | n/a | | n/a | | n/a | | 62,809 | | 11.718 | | 735,996 | |
2013 | | January 7, 2014 | | 6,587 | | 12.334 | | 81,244 | | 406 | | 12.334 | | 5,008 | | n/a | | n/a | | n/a | |
2013 | | November 14, 2013 | | 6,518 | | 12.466 | | 81,253 | | 401 | | 12.466 | | 4,999 | | n/a | | n/a | | n/a | |
2013 | | August 9, 2013 | | 7,053 | | 11.520 | | 81,251 | | 434 | | 11.520 | | 5,000 | | n/a | | n/a | | n/a | |
2013 | | April 1, 2013 | | 6,598 | | 12.314 | | 81,248 | | 406 | | 12.314 | | 4,999 | | n/a | | n/a | | n/a | |
(10) Mr. Warwick’s salary earned for the year was 323,920 GBP. Salary and variable pay amounts for Mr. Warwick have been converted to Canadian dollars using an exchange rate of $1CAD = 0.5224 GBP for 2015, $1CAD = 0.5498 GBP for 2014, $1CAD = 0.6210 GBP for 2013.
Incentive Plan Awards
Outstanding Share-Based Awards & Option-Based Awards
There were no outstanding share-based and option-based awards as at December 31, 2015 as all have been fully paid out following the closing of the Repsol Transaction.
Incentive Plan Awards — Value Vested or Earned during the Year
The following table outlines the value of non-equity compensation earned and equity-based awards which vested during the recently completed financial year.
Values shown in Canadian Dollars
Named Executive Officers | | Non-Equity Incentive
Plan
Compensation-Value
Earned During the
Year1
($) | | Share-Based Awards –
Value Vested During
the Year2
($) | | Options-Based
Awards –
Value Vested During
the Year3
($) | |
Luis Cabra Dueñas | | n/a | | n/a | | n/a | |
Chief Executive Officer | | | | | | | |
John Rossall | | 249,267 | | 1,327,708 | | 0 | |
Executive Director, North America | | | | | | | |
David Newby | | 157,500 | | 1,029,615 | | 0 | |
Senior Vice President, Finance, Treasurer and Chief Financial Officer | | | | | | | |
Harold N. Kvisle | | 0 | | 8,068,997 | | n/a | |
Former President and Chief Executive Officer | | | | | | | |
Paul R. Smith | | 0 | | 5,582,083 | | 0 | |
Former Executive Vice-President, Finance and Chief Financial Officer | | | | | | | |
A. Paul Blakeley | | 0 | | 5,557,329 | | 0 | |
Former Executive Vice-President, Asia Pacific | | | | | | | |
Paul C. Warwick | | 0 | | 6,467,010 | | 0 | |
Former Executive Vice-President, Europe & Atlantic | | | | | | | |
(1) Amounts shown are variable pay related to the 2015 performance year, paid in April 2016. Mr. Newby’s employment will end in 2016. As a result, his 2015 VPP will be paid at target in accordance with the terms of his employment contract.
(2) Amounts for Messrs. Rossall, Newby, Smith, Blakeley and Warwick include the value of PSUs granted in 2012 that vested in 2015; the value is calculated by multiplying the number of PSUs, including dividend equivalent PSUs, by the performance multiple (1.00) and by the average high and low price of the Company’s Common Shares on the TSX for the trading day immediately prior to the settlement date of March 2, 2015 ($9.715). Amounts for Messrs. Rossall and Newby also include the value of GRSUs granted in 2013 with one-third that vested in 2015; the value is calculated by multiplying the number of GRSUs, including dividend equivalent GRSUs and the five-day average closing price of the Company’s Common Shares on the TSX immediately prior to the settlement date of April 1, 2015 ($9.622). Amount for Mr. Kvisle includes the value of performance-based EDSUs granted in 2014 that vested in 2015; the value is calculated by multiplying the number of performance-based EDSUs, including dividend equivalent performance-based EDSUs, by the performance multiple (1.00) and by the previous five-day average closing price of the Company’s Common Shares on the TSX for the trading days immediately prior to the settlement date of February 27, 2015 ($9.71). These performance-based EDSUs converted to normal EDSUs on settlement. Amount for Mr. Kvisle also includes the value of EDSUs vested in 2015 granted in lieu of some salary and perquisites ($86,248), 2014 variable pay ($1,430,002) and 2014 pension ($1,296,200). Accelerated long-term incentives vesting as a result of the change of control have also been included. The value of all accelerated RSUs, GRSUs and PSUs, including dividend equivalent RSUs, GRSUs and PSUs is based on the release price of $9.677 for RSUs and GRSUs (based on the greater of $8.00 USD or CAD equivalent and the previous five-day average closing price) and the release price of $9.632 for PSUs (based on $8.00 USD or CAD equivalent as per outlined in the Arrangement Agreement).
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(3) The values noted represent the value that would have been realized by the NEO if options or cash units had been exercised on the vesting date. Where the share price on the vesting date was lower than the exercise price of the grant, a zero value is noted. All of the option-based awards were cancelled at the closing of the Repsol Transaction on May 8, 2015 in exchange for $0.01 USD or CAD equivalent of $0.01204 per option as per outlined in the Arrangement Agreement and these values have not been included as the value on the vesting date was $Nil.
Pension Plan Benefits
Defined Contribution Pension Plan
ROGCI provides Mr. Rossall and Mr. Newby with retirement benefits through two plans, both of which are defined contribution pension plans:
· �� The defined contribution component of the Employee Pension Plan, a registered contributory pension plan; and
· The Non-Registered Pension Plan, a non-registered non-contributory savings plan which provides the value of the Company pension contributions that exceeds the prescribed maximum under the Income Tax Act (Canada).
The Employee Pension Plan and the Non-Registered Pension Plan provide, in combination, Company pension contributions of 2% to 8% of base salary and variable pay, depending on service with the Company, as well as a match of employee contributions of 2% of base salary and variable pay. All Company pension contributions vest immediately.
Defined Contribution Plan Table
The following table presents the reconciliation of Mr. Rossall and Mr. Newby’s accruals under the defined contribution pension plans for 2015.
Named Executive Officers | | Accumulated Value at
Start of Year1 | | Compensatory Change in
Value in Year2
($) | | Non-Compensatory
Change in Value in Year3
($) | | Accumulated Value at End
of Year1
($) | |
Luis Cabra Dueñas | | n/a | | n/a | | n/a | | n/a | |
John Rossall | | 53,364 | | 33,845 | | 10,385 | | 80,662 | |
David Newby | | 112,295 | | 29,656 | | 13,489 | | 142,771 | |
(1) Represents the accumulated value in the Employee Pension Plan, excluding the accumulated value of the Non-Registered Pension Plan since this value is not available.
(2) In addition to Company contributions to the Employee Pension Plan, includes Company contributions to the Non-Registered Pension Plan of $16,931 and $12,669 for Messrs. Rossall and Newby.
(3) Includes employee contributions and investment earnings in the Employee Pension Plan.
Defined Benefit Pension Plans
Effective December 31, 2010, the registered pension plan applicable to Executive Officers hired prior to July 1, 2007 (the “Pre-2007 Registered Pension Plan”) was merged into the registered pension plan applicable to Executive Officers hired on or after July 1, 2007 (the “2007 Registered Pension Plan) to create the “Registered Pension Plan”. The provisions of the Pre-2007 Registered Pension Plan were incorporated into the Pre-2007 Component of the Registered Pension Plan, while the provisions of the 2007 Registered Pension Plan continued as the 2007 Component of the Registered Pension Plan. The Registered Pension Plan is a funded registered pension plan providing benefits up to the prescribed maximum under the Income Tax Act (Canada).
Pensions payable are in the form of a life annuity, with a 60% survivor benefit provided to the surviving spouse in the event of death of the retired member. Early retirement benefits are available from age 55. Pension benefits are unreduced if the member is age 60 or older. Otherwise, pension benefits are reduced by 5% for each year that early retirement precedes age 60. ROGCI can, but is not required to, provide increases to pensions in payment to reflect increases in the Consumer Price Index.
Defined Benefit Pension Plans for Executive Officers Hired or Appointed on or after July 1, 2007
ROGCI provided Former Executive Officer Mr. Smith with retirement benefits through two plans, both of which are non-contributory defined benefit pension plans:
· The 2007 Component of the Registered Pension Plan; and
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· The 2007 Supplementary Pension Plan, an unfunded non-registered supplementary executive retirement plan which provides pension benefits that exceed the prescribed maximum under the Income Tax Act (Canada). The 2007 Supplementary Pension Plan is secured with letters of credit held in a retirement compensation arrangement trust.
These plans are effective July 1, 2007 and cover designated Executive Officers hired or promoted on or after that date. Mr. Kvisle was not eligible to participate in these plans. As Mr. Warwick was not a Canadian resident, he was not eligible to participate in the 2007 Component of the Registered Pension Plan. The pension benefits that would have been provided to Mr. Warwick from the 2007 Component of the Registered Pension Plan were provided under the 2007 Supplementary Pension Plan. In addition to the Former Executive Officers listed above, one former executive officer accrued benefits in these plans during 2015.
Mr. Smith and Mr. Warwick terminated participation in the 2007 Component of the Registered Pension Plan and the 2007 Supplementary Pension Plan effective May 9, 2015 and September 30, 2015, respectively, and were granted an additional two years of credited service under the 2007 Supplementary Pension Plan in accordance with their employment contracts.
The 2007 Component of the Registered Pension Plan and the 2007 Supplementary Pension Plan provide, in combination, for an annual accrual of 2% of the total of Best Average Earnings and Final Average Award. The 2007 Supplementary Pension Plan also provides an additional annual accrual of 1% of the total of Best Average Earnings and Final Average Award for retirement on or after age 60, or upon discretionary approval by the Board. To date, the Board has not exercised this discretion. This provision assists ROGCI with the attraction and retention of executive talent. “Best Average Earnings” means the average of the best three years of base salary. “Final Average Award” means the average of the variable pay awarded during the last four consecutive years. Pension accruals after age 60 under the 2007 Supplementary Pension Plan are subject to the approval of the Board.
Defined Benefit Pension Plans for Executive Officers Hired or Appointed prior to July 1, 2007
ROGCI provided Mr. Blakeley with retirement benefits through two plans, both of which were non-contributory defined benefit pension plans:
· The Pre-2007 Component of the Registered Pension Plan; and
· The Pre-2007 Supplementary Pension Plan, an unfunded non-registered supplementary executive retirement plan which provides pension benefits that exceed the prescribed maximum under the Income Tax Act (Canada). The Pre-2007 Supplementary Pension Plan is secured with letters of credit held in a retirement compensation arrangement trust.
These plans were closed to new participants effective July 1, 2007. Mr. Blakeley was the only Executive Officer who accrued benefits in these plans during 2015. Mr. Blakeley terminated participation in the Pre-2007 Component of the Registered Pension Plan and the Pre-2007 Supplementary Pension Plan effective July 31, 2015 and was granted an additional two years of credited service under the Pre-2007 Supplementary Pension Plan in accordance with his employment contract.
For Executive Officers, the Pre-2007 Component of the Registered Pension Plan and the Pre-2007 Supplementary Pension Plan provide, in combination, for an annual accrual of 2% of the total of Best Average Earnings and Final Average Award. “Best Average Earnings” means the average of the best three years of base salary. “Final Average Award” means the average of the variable pay awarded during the last four consecutive years.
In 2004, the Company changed the pension accrual rate of the Pre-2007 Supplementary Pension Plan to provide greater flexibility in recognizing and recruiting executives with senior industry experience. The formula provides a pension accrual at a rate of 4% per year for all credited service to the earlier of seven years of participation in the Pre-2007 Registered Pension Plan or 14 years of Company service. For credited service after that date, pension is accrued at a rate of 2% per year. This enhancement provided Mr. Blakeley with an additional 2% accrual for his first 2.26 years of participation in the Pre-2007 Registered Pension Plan.
Mr. Blakeley was also entitled to a pension from the Talisman Sinopec Energy UK Ltd. (“TSEUK”) Pension Life and Scheme (the “UK Scheme”) relating to his service prior to becoming an Executive Officer. The UK Scheme provides for an annual pension of 1.9% of the final base salary per year of credited service. The credited service in the UK Scheme is limited to the period prior to becoming an Executive Officer, but the final base salary reflects service after becoming an Executive Officer and conversion from Canadian dollars to British pounds. UK Scheme benefits are payable in British pounds. Benefits are actuarially reduced for early retirement prior to age 65.
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Financial Position of Defined Benefit Plans
Following the methods prescribed under the International Accounting Standard (“IAS”) 19 (rev. 2011), the Registered Pension Plan has an excess of accrued obligations over assets of US$1,593,000 as at December 31, 2015, representing a decrease of US$301,000 from the unfunded accrued obligations of US$1,894,000 as at December 31, 2014.
The unfunded accrued obligations of the 2007 Supplementary Pension Plan are US$9,282,000 as at December 31, 2015, representing a decrease of US$2,443,000 from the unfunded accrued obligations of US$11,725,000 as at December 31, 2014.
The unfunded accrued obligations of the Pre-2007 Supplementary Pension Plan (including certain members of the defined benefit component of the Employee Pension Plan whose pension benefits exceed the prescribed maximum under the Income Tax Act (Canada) and who are also covered by the Pre-2007 Supplementary Pension Plan) are US$59,267,000 as at December 31, 2015, representing a decrease of US$14,573,000 from the unfunded accrued obligations of US$73,840,000 as at December 31, 2014.
Defined Benefit Plan Table
The following table outlines estimated annual benefits, accrued obligations and compensatory and non-compensatory changes in accrued obligations in 2015 for the Former Executive Officers under the defined benefit pension plans. The reported values are based on actuarial assumptions and methods that are consistent with those used to calculate the accrued benefit obligation and the net benefit expense disclosed in ROGCI’s Consolidated Financial Statements.
Values shown in Canadian Dollars
Named Executive Officers | | Years of
Credited
Service1 | | Annual
Benefits at
End of Year2
($) | | Accrued
Obligation
at Start of
Year
($) | | Compensatory
Change in
Accrued
Obligation in
Year3
($) | | Non-
Compensatory
Change in
Accrued in
Obligation in
Year4
($) | | Accrued
Obligation at
End of Year
($) | |
Harold N. Kvisle5 | | n/a | | n/a | | n/a | | n/a | | n/a | | n/a | |
Paul R. Smith | | n/a | | n/a | | 4,646,500 | | 201,900 | | (1,730,200 | ) | n/a6 | |
A. Paul Blakeley | | 22.6577 | | 485,5808 | | 8,680,200 | | 1,148,500 | | 2,195,600 | | 12,024,300 | |
Paul C. Warwick | | 5.333 | | 193,055 | | 1,567,700 | | 2,336,800 | | (34,700 | ) | 3,869,800 | |
(1) Years of credited service at termination of employment, including 2 years of additional credited service granted in accordance to Mr. Blakeley and Mr. Warwick’s employment contracts.
(2) Annual lifetime benefit payable at December 31, 2015, reflecting the 2 years of additional credited service granted in accordance to Mr. Blakeley and Mr. Warwick’s employment contracts.
(3) Represents the current service cost plus the impact of other compensation-related items such as plan changes and pensionable earnings different than estimated.
(4) Represents the interest on the accrued obligation and the impact of changes in assumptions.
(5) Mr. Kvisle is not eligible to participate in the defined benefit pension plans.
(6) There is no accrued obligation for Mr. Smith as at December 31, 2015 because a lump sum of $3,118,200, representing the commuted value of his pension benefits accrued under the 2007 Component of the Registered Pension Plan and the 2007 Supplementary Pension Plan was paid to Mr. Smith in 2015.
(7) Includes 11.74 years of credited service in the UK Pension Scheme.
(8) Mr. Blakeley has not yet made a pension election under the UK Pension Scheme. The annual benefits at December 31, 2015 includes the pension payable under the UK Pension Scheme as at December 31, 2015 assuming that Mr. Blakeley elects a pension commencing on July 31, 2015, disregarding any potential pension reduction due to the payment of a tax-free cash sum and a Lifetime Allowance Charge from the UK Pension Scheme.
Employment Contracts and Termination
Termination Following a Change of Control or Termination Without Cause
ROGCI employment contracts are in place for Mr. Rossall and Mr. Newby (Mr. Cabra does not have a contract with ROGCI), which contain provisions for payments upon termination without cause or termination following a change of control. A change of control is deemed to have occurred as a result of any of the following events:
· Any person, partnership, entity or group acquires direct or indirect, actual or de facto control of the Company (where “control” means the ability to elect a majority of the Board of ROGCI and “group” refers to a combination of persons, partnerships, or entities, or any of the foregoing that act in concert);
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· If there is any acquisition of 40% or more of the shares of the Company having entitlement to vote in the election of directors the Company by any person, partnership, entity or group, any such acquisition shall be deemed to constitute an acquisition of control;
· The Company enters into an amalgamation, arrangement, restructuring, reorganization, merger or consolidation arrangement whereby, or the ultimate effect of which is that, any person, partnership, entity or group, whosoever composed, acquires direct or indirect, actual or de facto control of the Company;
· The shareholders of the Company approve the liquidation, winding up or other dissolution of the Company; and
· The shareholders of the Company approve the sale of all or substantially all of the assets of the Company.
Effective January 1, 2012, contracts for all newly hired Executive Officers, including Mr. Rossall and Mr. Newby, include a requirement for termination of employment by the Company following a change of control for Executive Officers (“double-trigger”) for the termination benefits to become payable.
Both Mr. Rossall and Mr. Newby were employed as at December 31, 2015. Mr. Newby’s employment will end in 2016 and his termination payment will be paid in accordance with his employment contract.
A description of the Executive Officer employment contracts follow, including a summary of potential payments in the event of a termination without cause or following a change of control.
| | Executive Officers |
Conditions and Obligations of Employment | | · Confidentiality Clause (applicable any time after ceasing to be an employee of the Company);
· Non-Compete Clause (applicable during the term of employment with the Company and for a period of 12 months thereafter); and
· Non-Solicitation Clause (applicable during the term of employment with the Company and for a period of 12 months thereafter). |
| | Severance Payment |
Potential Payments in the event of Termination without Cause or Termination following a Change of Control | | · 2.0x annual base salary;
· 2.0x annual target variable pay;
· Annual variable pay target amount in respect of the year preceding the date of termination, if the date of termination precedes the date upon which such variable pay amount would have been paid; and
· Pro rata portion of the annual variable pay target for the portion of the current year up to date of termination. |
| | Pension Benefits |
| | · Participation in the defined contribution pension plans ends, and Executive Officer entitled to account balance; and
· Cash payment representing an additional 2.0 years of Company contributions to the defined contribution pension plans. |
| | Additional Items |
| | · Option to purchase the personally assigned company vehicle;
· Lump sum equal to 15% of 2.0x annual base salary and 2.0x annual target variable pay as compensation for loss of all other benefits1;
· Management termination, legal and tax counseling services, with a maximum of $10,000 for management counseling services and $8,500 combined for legal and tax counseling services; and
· Liability insurance and/or indemnity coverage. |
| | Retention Payment |
| | · Mr. Rossall will receive a prorated portion of his award for the year of accrual and Mr. Newby will receive the full award upon termination. |
(1) The calculation of the lump sum for loss of benefits does not include the amounts for i) the annual variable pay target in respect of the year preceding the date of termination, if the date of termination precedes the date upon which such variable pay amount would have been paid, and ii) the pro rata portion of the annual variable pay target for the portion of the current year up to date of termination.
The following table reflects the estimated incremental payments current Executive Officers would have been entitled to in the event of termination without cause or following a change of control on December 31, 2015.
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Values shown in Canadian Dollars
Former Executive Officers | | Severance
Payment1
($) | | Benefits2
($) | | Non-Equity Non-
Annual Incentive
Plan Termination
Without
Cause3
($) | | Pension4
($) | |
Luis Cabra Dueñas | | n/a | | n/a | | n/a | | n/a | |
Chief Executive Officer | | | | | | | | | |
John Rossall | | 1,846,688 | | 239,794 | | 623,333 | | 72,765 | |
Executive Director, North America | | | | | | | | | |
David Newby | | 1,172,500 | | 152,250 | | 185,500 | | 71,050 | |
Senior Vice President, Finance, Treasurer and Chief Financial Officer | | | | | | | | | |
(1) Includes the total value of severance payment as defined in the employment contract.
(2) Lump sum equal to 15% of 2.0x annual base salary and 2.0x annual target variable pay as compensation for loss of all other benefits.
(3) Mr. Rossall will receive a prorated portion of the first payment of his award and Mr. Newby will receive the full award if they were terminated without cause or if a change of control occurred on December 31, 2015.
(4) Represents an additional 2.0 years of Company contributions to the defined contribution pension plans.
Termination Following Resignation, Retirement, Death and Termination for Cause
The following table illustrates the action taken for current Executive Officers in the event of resignation, retirement, death and termination for cause:
Salary | | Salary ends in the event of resignation, retirement, death or termination for cause. |
Benefit Programs | | Benefit programs end in the event of resignation, death or termination for cause.
Retirement: Life insurance of $50,000, reducing by 20% on the first four retirement anniversaries; medical coverage continues with lifetime maximum of $5,000 per covered person. |
Variable Pay | | Resignation: Not paid.
Retirement: Paid in respect of preceding year (if retirement date precedes the date upon which the variable pay would have been paid) and payment for current year (on pro rata basis) to be paid at same time as all employees.
Death: Paid in respect of preceding year (if death precedes the date upon which the variable pay would have been paid) and payment for current year (on pro rata basis) to be paid at same time as all employees.
Termination for Cause: Not paid. |
Retention Awards | | Resignation: Not paid.
Termination for Cause: For Mr. Rossall, any unpaid amounts are forfeited and for Mr. Newby, no payment will be provided. |
Pension Benefits | | Participation in the defined contribution pension plans ends in the event of resignation, retirement, death or termination for cause, with Executive Officer or beneficiary entitled to account balance. |
Former Executive Officer Departure and Compensation
The ROGCI Board approved the termination of Mr. Kvisle as President and CEO effective May 9, 2015 (concurrent with the closing of the Repsol Transaction). The Board approved Mr. Kvisle’s separation provisions in accordance with the terms of his employment contract. Also in accordance with the terms of his employment contract, Mr. Kvisle received reasonable financial and legal services. No other discretion was applied by the Board. Pursuant to the terms of the grant agreements, all unvested LTIP vest immediately upon change of control.
The ROGCI Board approved the termination of Messrs. Smith, Blakeley and Warwick effective May 9, 2015, July 31, 2015 and September 30, 2015, respectively. Each Former Executive Officer received severance payments in accordance with the terms of their employment contracts. Also in accordance with the terms of their employment contracts, they received reasonable financial, legal and executive career transitioning services. Pursuant to the terms of the grant agreements, all unvested LTIP vested immediately upon change of control.
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The following table reflects the payments Former Executive Officers received as part of their termination arrangements.
Values shown in Canadian Dollars
Former Executive Officers | | Salary1
($) | | Target
Variable
Pay2
($) | | 2015
Variable
Pay3
($) | | Benefits4
($) | | Pension5
($) | | All Other
Payments6
($) | | Total Value
of Severance
Package
($) | |
Harold N. Kvisle | | 3,250,000 | | 3,575,000 | | 505,397 | | — | | — | | 3,732,800 | | 11,063,197 | |
President and Chief Executive Officer | | | | | | | | | | | | | | | |
Paul R. Smith | | 1,370,000 | | 1,027,500 | | 181,572 | | 386,861 | | 147,900 | | — | | 3,113,833 | |
Former Executive Vice-President, Finance and Chief Financial Officer | | | | | | | | | | | | | | | |
A. Paul Blakeley | | 1,370,000 | | 1,027,500 | | 298,397 | | 404,385 | | 1,130,000 | | — | | 4,230,282 | |
Former Executive Vice-President. Asia Pacific | | | | | | | | | | | | | | | |
Paul C. Warwick | | 1,370,000 | | 1,027,500 | | 384,257 | | 359,625 | | 1,788,000 | | — | | 4,929,382 | |
Former Executive Vice-President, Europe & Atlantic | | | | | | | | | | | | | | | |
(1) Mr. Kvisle received 2.5x annual base salary and Messrs. Smith, Blakeley and Warwick received 2.0x annual base salary. Mr. Warwick’s employment contract uses a salary of CAD $685,000 for severance amounts.
(2) Mr. Kvisle received 2.5x target variable pay and Messrs. Smith, Blakeley and Warwick received 2.0x target variable pay.
(3) Pro rata portion of the annual variable pay target for the portion of the current year up to the date of separation.
(4) Mr. Kvisle did not receive a lump sum for loss of all other benefits. For Messrs. Smith and Blakeley, the lump sum is equal to 15% of 2.0x annual base salary, 2.0x annual target variable pay and pro rata portion of 2015 target variable pay, and for Mr. Warwick, the lump sum is equal to 15% of 2.0x annual base salary and 2.0x annual target variable pay as compensation for loss of all other benefits.
(5) This amount does not include Mr. Smith’s payment of $2,970,300 reflecting his 6.167 years of accrued credited service in the defined benefit pension plans prior to the change of control. This amount does not include the accrued obligation of $10,894,300 for Mr. Blakeley’s 20.657 years of credited service in the defined benefit pension plans and the UK Pension Scheme and the accrued obligation of $2,081,800 for Mr. Warwick’s 3.333 years of credited service in the defined benefit pension plans prior to change of control.
(6) For Mr. Kvisle, includes $3,732,800 representing the incremental value of pension benefits as of May 9, 2015 he would have received had he participated in the defined benefit pension plans. This amount does not include the payment of $836,300 received by Mr. Kvisle in lieu of the compensatory value he would have received prior to change of control in 2015 had he participated in the defined benefit pension plans.
Change of control and termination values reported in the table above do not include long-term incentive payments that occurred upon the closing of the Repsol Transaction, as these have been included in the table under the heading “Incentive Plan Awards — Value Vested or Earned during the Year”.
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DIRECTOR COMPENSATION
This section describes the Company’s director compensation components and approach to director compensation for the periods January 1 to May 8, 2015 and May 8, 2015 to December 31, 2015.
For the purposes of this Director Compensation section, “director” means non-executive director unless otherwise indicated. All numbers/values in this section are rounded up/down to the nearest whole number/value.
Compensation Philosophy and Program Design
Prior to May 8, 2015, directors’ compensation was designed to align directors’ interests with shareholders and the long-term success of the Company and attract and retain qualified directors while being competitive with comparable public companies. In addition to a cash retainer, directors received a portion of their compensation in the form of director deferred share units (“DDSUs”), which could not be redeemed until they ceased to be a director of the Company and if applicable, cease to be an employee of the Company or an affiliate as provided for in the plan governing the DDSUs (the “DDSU Plan”). The value of DDSUs tracked the performance of the Company’s Common Shares. Directors could voluntarily elect to receive all or a portion of their annual cash retainer and fees in the form of DDSUs.
On July 7, 2015, the Directors ratified a new remuneration structure for non-employee directors on the recommendation of the Company’s ultimate parent. Directors who are salaried employees of the Company or Repsol and affiliates, receive no remuneration for serving as directors. Fees to non-executive directors are paid in cash and there are no additional meeting fees or LTIP awards.
Annual Compensation Review Process
Prior to May 8, 2015, the Governance and Nominating Committee reviewed, on an annual basis, director compensation. Given the pending acquisition and in anticipation that a new Board and compensation structure would be implemented by Repsol, the Committee did not undertake such a review in the first two quarters of 2015.
Effective May 8, 2015, all compensation will be reviewed from time to time with support and recommendation from Repsol.
Director Compensation Elements
Quantum and Structure of Pay
For the periods noted below, each director of Talisman was remunerated according to the fee schedule provided below. All fees are paid to directors in Canadian dollars.
Director Fee Schedule for Period January 1 to May 8, 2015
| | Fee |
Chairman of the Board Annual Retainer1 | | $200,000 |
Annual Retainer for Other Directors | | $50,000 |
Board Meeting Fee | | $1,700 ($800 for teleconference) |
Audit Committee Chair Retainer | | $25,000 |
Audit Committee Member Retainer | | $10,000 |
Committee Chair Retainer | | $15,000 |
Committee Member Retainer | | $6,000 |
Committee Attendance Fee | | $1,700 ($800 for teleconference) |
Equity grant (Chairman)2 | | $300,000 (in DDSUs) |
Equity grant (Director)2 | | $150,000 (in DDSUs) |
(1) The Chairman’s annual retainer was an all-inclusive retainer. No additional fees were paid for attendance at Board or Board Committee meetings, or for service on other Company-related matters.
(2) Directors who were elected or appointed after an annual equity grant were eligible for a pro-rated DDSU award for the period from election or appointment to the next annual equity grant.
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Director1 Fee Schedule for Period May 8 to December 31, 2015
| | Fee | |
Annual Retainer2 | | $ | 110,000 | |
Audit Committee Chair Retainer | | $ | 20,000 | |
Audit Committee Member Retainer | | $ | 10,000 | |
(1) Directors who are salaried employees of the Company or Repsol and affiliates receive no remuneration for serving as directors.
(2) Fee is based on an estimated five Board meetings per year.
In addition to the above, directors are reimbursed for their Company-related travel expenses.
Long-Term Incentive Plans
Director Deferred Share Unit Plan
No deferred share units were granted to directors in 2015 under the DDSU plan in place prior to the Repsol Transaction. There are currently no DDSUs outstanding under this plan. All DDSUs were paid out after closing of the acquisition in accordance with the provisions of the DDSU Plan. The DDSU Plan was terminated on May 6, 2015.
Director Stock Option Plan
No stock options have been granted to non-executive directors under the Director Stock Option Plan (“DSOP”) since 2003. There are no options currently outstanding under this plan. The DSOP was terminated on May 6, 2015.
Director Compensation Tables
Compensation
During 2015, directors earned the following compensation pursuant to the applicable director fee schedule:
Name | | Total
Fees4
($) | | Fees Earned
in Cash
($) | | Fees
Credited in
DDSU5
($) | | All Other
Compensation | | Total
Compensation
($) | |
Albrecht W.A. Bellstedt2 | | 77,802 | | 77,802 | | N/A | | | | 77,802 | |
Christiane Bergevin1 | | 29,473 | | 14,736 | | 14,737 | | | | 29,473 | |
Donald J. Carty1 | | 33,780 | | 33,780 | | | | | | 33,780 | |
Jonathan Christodoro1 | | 31,973 | | 31,973 | | | | | | 31,973 | |
Thomas W. Ebbern3 | | 113,793 | | 77,802 | | 35,990 | | | | 113,792 | |
Brian M. Levitt1 | | 29,473 | | | | 29,473 | | | | 29,473 | |
Samuel J. Merksamer1 | | 23,046 | | 23,046 | | | | | | 23,046 | |
Robert R. Rooney2 | | 71,319 | | 71,319 | | N/A | | 5,5186 | | 76,837 | |
Lisa A. Stewart1 | | 35,162 | | 17,720 | | 17,442 | | | | 35,162 | |
Henry W. Sykes1 | | 32,973 | | 32,973 | | | | | | 32,973 | |
Peter W. Tomsett1 | | 33,462 | | | | 33,462 | | | | 33,462 | |
Michael T. Waites3 | | 123,792 | | 84,286 | | 39,506 | | | | 123,792 | |
Charles R. Williamson1 | | 70,879 | | | | 70,879 | | | | 70,879 | |
Charles M. Winograd1 | | 32,980 | | 16,490 | | 16,490 | | | | 32,980 | |
(1) Compensation is shown for the period prior to the individual’s resignation from the Board in conjunction with the Repsol Transaction on May 8, 2015.
(2) Compensation is shown for the period following the individual’s election to the Board in conjunction with the Repsol Transaction on May 8, 2015.
(3) Compensation is shown for the period January 1 to December 31, 2015. Messrs. Ebbern and Waites were the only directors serving prior to the Repsol Transaction to be elected to the Board following the Repsol Transaction.
(4) Includes annual retainer, committee retainer and attendance fees, as applicable.
(5) For the period January 1 to May 8, 2015 a director could elect a portion of his or her annual retainer, committee retainer and attendance fees in DDSUs. The number of DDSUs credited to a director’s account was calculated by dividing the value of the DDSU by the mean of the high and low reported prices at which Common shares were traded on the TSX on the day preceding the grant date. DDSUs could not be redeemed until a director ceased to be a director, and, if applicable, ceased to be an employee of the Company or an affiliate, as provided in the DDSU Plan. No equity DDSU grants were awarded in 2015.
(6) In addition to an annual retainer, Mr. Rooney receives a parking benefit.
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Outstanding Share-Based Awards
As at December 31, 2015, there were no share-based awards outstanding for the benefit of directors.
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REPSOL OIL & GAS CANADA INC.
Suite 2000, 888 — 3rd Street SW
Calgary, Alberta, Canada T2P 5C5
P 403.237.1234 F 403.237.1902
E infocanada@repsol.com
www.repsol.com/ca_en/
