¨ | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR | |
x | ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
x Annual information form | ¨ Audited annual financial statements |
Form | Registration No. |
F-10 | 333-208588 |
• | anticipated business prospects |
• | our financial and operational performance, including the performance of our subsidiaries |
• | expectations or projections about strategies and goals for growth and expansion |
• | expected cash flows and future financing options available to us |
• | expected costs for planned projects, including projects under construction and in development |
• | expected schedules for planned projects (including anticipated construction and completion dates) |
• | expected regulatory processes and outcomes |
• | expected common share purchases under our normal course issuer bid |
• | expected impact of regulatory outcomes |
• | expected outcomes with respect to legal proceedings, including arbitration and insurance claims |
• | expected capital expenditures and contractual obligations |
• | expected operating and financial results |
• | the expected impact of future accounting changes, commitments and contingent liabilities |
• | expected industry, market and economic conditions. |
• | inflation rates, commodity prices and capacity prices |
• | timing of financings and hedging |
• | regulatory decisions and outcomes |
• | foreign exchange rates |
• | interest rates |
• | tax rates |
• | planned and unplanned outages and the use of our pipeline and energy assets |
• | integrity and reliability of our assets |
• | access to capital markets |
• | anticipated construction costs, schedules and completion dates |
• | acquisitions and divestitures. |
• | our ability to successfully implement our strategic initiatives |
• | whether our strategic initiatives will yield the expected benefits |
• | the operating performance of our pipeline and energy assets |
• | amount of capacity sold and rates achieved in our pipeline businesses |
• | the availability and price of energy commodities |
• | the amount of capacity payments and revenues we receive from our energy business |
• | regulatory decisions and outcomes |
• | outcomes of legal proceedings, including arbitration and insurance claims |
• | performance and credit risk of our counterparties |
• | changes in market commodity prices |
• | changes in the political environment |
• | changes in environmental and other laws and regulations |
• | competitive factors in the pipeline and energy sectors |
• | construction and completion of capital projects |
• | costs for labour, equipment and materials |
• | access to capital markets |
• | interest, tax and foreign exchange rates |
• | weather |
• | cybersecurity |
• | technological developments |
• | economic conditions in North America as well as globally. |
TRANSCANADA PIPELINES LIMITED | ||
Per: | /s/ DONALD R. MARCHAND | |
DONALD R. MARCHAND Executive Vice-President, Corporate Development and Chief Financial Officer | ||
Date: March 14, 2016 |
EXHIBITS | |
*13.1 | Management's discussion and analysis (included on pages 1 through 110 of the TCPL 2015 Management's discussion and analysis and audited financial statements). |
*13.2 | 2015 Audited consolidated financial statements (included on pages 111 through 173 of the TCPL 2015 Management's discussion and analysis and audited financial statements)), including the auditors' report thereon. |
13.3 | TCPL's Annual information form for the year ended December 31, 2015. |
* previously filed | |
31.1 | Certification of Chief Executive Officer pursuant to Section 102 of the Sarbanes-Oxley Act of 2002. |
31.2 | Certification of Chief Financial Officer pursuant to Section 102 of the Sarbanes-Oxley Act of 2002. |
• | anticipated business prospects |
• | our financial and operational performance, including the performance of our subsidiaries |
• | expectations or projections about strategies and goals for growth and expansion |
• | expected cash flows and future financing options available to us |
• | expected costs for planned projects, including projects under construction and in development |
• | expected schedules for planned projects (including anticipated construction and completion dates) |
• | expected regulatory processes and outcomes |
• | expected common share purchases under our normal course issuer bid |
• | expected impact of regulatory outcomes |
• | expected outcomes with respect to legal proceedings, including arbitration and insurance claims |
• | expected capital expenditures and contractual obligations |
• | expected operating and financial results |
• | the expected impact of future accounting changes, commitments and contingent liabilities |
• | expected industry, market and economic conditions. |
2 | TCPL Annual information form 2015 |
• | inflation rates, commodity prices and capacity prices |
• | timing of financing and hedging |
• | regulatory decisions and outcomes |
• | foreign exchange rates |
• | interest rates |
• | tax rates |
• | planned and unplanned outages and the use of our pipeline and energy assets |
• | integrity and reliability of our assets |
• | access to capital markets |
• | anticipated construction costs, schedules and completion dates |
• | acquisitions and divestitures. |
• | our ability to successfully implement our strategic initiatives |
• | whether our strategic initiatives will yield the expected benefits |
• | the operating performance of our pipeline and energy assets |
• | amount of capacity sold and rates achieved in our pipelines businesses |
• | the availability and price of energy commodities |
• | the amount of capacity payments and revenues we receive from our energy business |
• | regulatory decisions and outcomes |
• | outcomes of legal proceedings, including arbitration and insurance claims |
• | performance and credit risk of our counterparties |
• | changes in the political environment |
• | changes in environmental and other laws and regulations |
• | competitive factors in the pipeline and energy sectors |
• | construction and completion of capital projects |
• | costs for labour, equipment and material |
• | access to capital markets |
• | interest, tax and foreign exchange rates |
• | weather |
• | cybersecurity |
• | technological developments |
• | economic conditions in North America as well as globally. |
TCPL Annual information form 2015 | 3 |
Date | Event |
March 21, 1951 | Incorporated by Special Act of Parliament as Trans‑Canada Pipe Lines Limited. |
April 19, 1972 | Continued under the Canada Corporations Act by Letters Patent, which included the alteration of its capital and change of name to TransCanada PipeLines Limited. |
June 1, 1979 | Continued under the Canada Business Corporations Act (CBCA). |
July 2, 1998 | Certificate of Arrangement issued in connection with the Plan of Arrangement with NOVA Corporation under which the companies merged and then split off the commodity chemicals business carried on by NOVA Corporation into a separate public company. |
January 1, 1999 | Certificate of Amalgamation issued reflecting TCPL's vertical short form amalgamation with a wholly owned subsidiary, Alberta Natural Gas Company Ltd. |
January 1, 2000 | Certificate of Amalgamation issued reflecting TCPL's vertical short form amalgamation with a wholly owned subsidiary, NOVA Gas International Ltd. |
May 4, 2001 | Restated TransCanada PipeLines Limited Articles of Incorporation filed. |
June 20, 2002 | Restated TransCanada PipeLines Limited By-Laws filed. |
May 15, 2003 | Certificate of Arrangement issued in connection with the plan of arrangement with TransCanada. TransCanada was incorporated pursuant to the provisions of the CBCA on February 25, 2003. The arrangement was approved by TCPL common shareholders on April 25, 2003 and following court approval, Articles of Arrangement were filed making the arrangement effective May 15, 2003. The common shareholders of TCPL exchanged each of their common shares of TCPL for one common share of TransCanada. The debt securities and preferred shares of TCPL remained obligations and securities of TCPL. TCPL continues to carry on business as the principal operating subsidiary of the TransCanada group of entities. |
4 | TCPL Annual information form 2015 |
TCPL Annual information form 2015 | 5 |
Date | Description of development |
Canadian Regulated Pipelines | |
NGTL SYSTEM | |
January 2013 | The NEB issued its recommendation to the Governor-in-Council that the proposed Chinchaga Expansion component of the Komie North project be approved, but denied the proposed Komie North Extension component. |
April 2013 | The Leismer-Kettle River Crossover project was placed into service. The cost of the expansion was $150 million. |
March 2014 | We received an NEB Safety Order (the Order) in response to the recent pipeline releases on the NGTL System. The Order required us to reduce the maximum operating pressure on three per cent of NGTL’s pipeline segments. We filed a request for a review and variance of the Order that would minimize gas disruptions while still maintaining a high level of safety, which the NEB granted in April 2014 subject to certain conditions. We accelerated components of our integrity management program to address the NEB Order. |
March 2014 | The NEB approved approximately $400 million in NGTL facility expansions. |
Fourth Quarter 2014 | We continued to experience significant growth on the NGTL System as a result of growing natural gas supply in northwestern Alberta and northeastern British Columbia (B.C.) from unconventional gas plays and substantive growth in intra-basin delivery markets. This demand growth was driven primarily by oil sands development, gas-fired electric power generation and expectations of B.C. west coast LNG projects. |
First Quarter 2015 | The NGTL System had approximately $6.7 billion of new supply and demand facilities under development and we continued to advance several of these capital expansion projects by filing the regulatory applications with the NEB. We also received additional requests for firm receipt service. |
Fourth Quarter 2015 / First Quarter 2016 | In 2015, we placed approximately $350 million of facilities in service. For 2016, the NGTL System continues to develop a further approximately $7.3 billion of new supply and demand facilities. We have approximately $2.3 billion of facilities that have received regulatory approval with approximately $450 million currently under construction. We have filed for approval for a further approximately $2.0 billion of facilities which are currently under regulatory review. Applications for approval to construct and operate an additional $3.0 billion of facilities have yet to be filed. Included in our capital program is the recently announced 2018 expansion of a further $600 million of facilities required on the NGTL System. The 2018 expansion includes multiple projects totaling approximately 88 km (55 miles) of 20-to 48-inch diameter pipeline, one new compressor, approximately 35 new and expanded meter stations and other associated facilities. Applications to construct and operate the various components of the 2018 expansion program will be filed with the NEB between second quarter and fourth quarter 2016. Subject to regulatory approvals, construction is expected to start in 2017, with all facilities expected to be in service in 2018. |
North Montney Mainline | |
August 2013 | We signed agreements for firm gas transportation services to underpin the development of a major pipeline extension and expansion of the NGTL System to receive and transport natural gas from the North Montney area of B.C. We also entered into arrangements with other parties for transportation services that will utilize the North Montney Mainline project facilities. |
June 2015 | The NEB approved the $1.7 billion North Montney Mainline project subject to certain terms and conditions. Under one of these conditions, construction on the North Montney Mainline project can only begin after a positive final investment decision (FID) has been made on the proposed Pacific NorthWest (PNW) LNG project. The North Montney Mainline will provide substantial new capacity on the NGTL System to meet the transportation requirements associated with rapidly increasing development of natural gas resources in the Montney supply basin in northeastern B.C. The project will connect Montney and other WCSB supply to both existing and new natural gas markets, including LNG markets. The North Montney Mainline project will consist of two large diameter 42-inch pipeline sections, Aitken Creek and Kahta, totaling approximately 301 km (187 miles) in length, and associated metering facilities, valve sites and compression facilities. The project will also include an interconnection with our proposed Prince Rupert Gas Transmission Project (PRGT) to provide natural gas supply to the proposed PNW LNG liquefaction and export facility near Prince Rupert, B.C. We expect to have the Aitken Creek and Kahta sections in service in 2017. |
Merrick Mainline | |
June 2014 | We announced the signing of agreements for approximately 1.9 Bcf/d of firm natural gas transportation services to underpin the development of a major extension of our NGTL System, with the expectation for the Merrick Mainline to be in service in first quarter 2020. The Merrick Mainline pipeline will transport natural gas sourced through the NGTL System to the inlet of the proposed Pacific Trail Pipeline terminating at the Kitimat LNG Terminal near Kitimat, B.C. |
First Quarter 2016 | The proposed Merrick Mainline pipeline project has been delayed. In late 2015, the Kitimat LNG partners advised us that they are re-phasing the pace of Kitimat LNG facility development. Since the Merrick Mainline is dependent upon the construction of the downstream infrastructure, the in-service date of the Merrick Mainline will be no earlier than 2021. The Merrick Mainline is a $1.9 billion project that will consist of approximately 260 kilometres (161 miles) of 48-inch diameter pipe. |
6 | TCPL Annual information form 2015 |
Date | Description of development |
NGTL Revenue Requirement Settlements | |
August 2013 | We reached settlement of the NGTL System annual revenue requirement for the years 2013 and 2014 with shippers and other interested parties (the NGTL 2013 – 2014 Settlement). The settlement fixed the ROE at 10.10 per cent on 40 per cent deemed common equity, established an increase in the composite depreciation rate to 3.05 per cent and 3.12 per cent for 2013 and 2014, respectively, and fixed the OM&A costs for 2013 at $190 million and 2014 at $198 million with any variance to our account. We also requested and received approval for changes to existing interim rates to reflect the settlement, effective September 1, 2013, pending a decision on the settlement application. |
November 2013 | The NEB approved the NGTL 2013 - 2014 Settlement and final 2013 rates, as filed, in November 2013. |
October 2014 | We reached a revenue requirement settlement with our shippers for 2015 on the NGTL System. The terms of the one year settlement included no changes to the ROE of 10.10 per cent on 40 per cent deemed equity, a continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed OM&A expense amount. The settlement was filed with the NEB in October 2014. |
February 2015 | We received NEB approval for our revenue requirement settlement with our shippers for 2015 on the NGTL System. The terms of the one year settlement include continuation of the 2014 ROE of 10.10 per cent on 40 per cent deemed equity, continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed OM&A expense amount that is based on an escalation of 2014 actual costs. |
December 2015 | We reached a two-year revenue requirement agreement with customers and other interested parties on the annual costs, including return on equity and depreciation required to operate the NGTL System for 2016 and 2017. The agreement fixes the equity return at 10.1 per cent on 40 per cent deemed common equity, establishes depreciation at a forecast composite rate of 3.16 per cent and fixes OM&A costs at $222.5 million annually. An incentive mechanism for variances will enable NGTL to capture savings from improved performance and provide for the flow-through of all other costs, including pipeline integrity expenses and emissions costs. NGTL filed on December 1, 2015 with the NEB for approval of the agreement. |
CANADIAN MAINLINE | |
January 2014 | Shippers on the Canadian Mainline elected to renew approximately 2.5 Bcf/d of their contracts through November 2016. |
Mainline Settlement & Tolls and Tariff Applications and LDC Settlement | |
March 2013 | We received the NEB decision on our Canadian Restructuring Proposal application to change the business structure and the terms and conditions of service for the Canadian Mainline. The NEB decision established a Toll Stabilization Account (TSA) to capture the surplus or the shortfall between our revenues and our cost of service for each year over the five year term of the decision. The NEB decision also identified certain circumstances that would require a new tolls application prior to the end of the five year term. One of those circumstances is if the TSA balance becomes positive, which occurred in 2013. Subsequently, we filed a review and variance application with the NEB in May 2013, which was dismissed in June 2013 and the NEB set out a process to consider the tariff revisions. |
July 2013 | The NEB released its reasons for the dismissal of our review and variance application. Additional changes to the Canadian Mainline’s tariff were considered by the NEB as a separate application which was heard in an oral hearing. We began implementation of the NEB decision related to the Canadian Restructuring Proposal. The implementation of the NEB decision was a key priority in 2013 and with the ability to price discretionary services at market prices we were able to essentially meet our overall cost of service requirements for 2013. |
September 2013 | The Canadian Mainline and the three largest Canadian local distribution companies (LDCs) entered into a settlement (LDC Settlement) which was filed with the NEB for approval in December 2013. The LDC Settlement proposed to establish new fixed tolls for 2015 to 2020 and maintain tolls for 2014 at the current rates. The LDC Settlement calculated tolls for 2015 on a base ROE of 10.10 per cent on 40 per cent deemed common equity. It also included an incentive mechanism that required a $20 million (after tax) annual contribution by us from 2015 to 2020, which could have resulted in a range of ROE outcomes from 8.70 per cent to 11.50 per cent. The LDC Settlement would have enabled the addition of facilities in the Eastern Triangle to serve immediate market demand for supply diversity and market access. The LDC Settlement was intended to provide a market driven, stable, long-term accommodation of future demand in this region in combination with the anticipated lower demand for transportation on the Prairies Line and the Northern Ontario Line while providing a reasonable opportunity to recover our costs. The LDC Settlement also retained pricing flexibility for discretionary services and implemented certain tariff changes and new services as required by the terms of the settlement. |
March 2014 | The NEB responded to the LDC Settlement application we filed in December 2013. The NEB did not approve the application as a settlement but allowed us the option to continue with the application as a contested tolls application, amend the application or terminate the processing of the application. We amended the application with additional information. |
November 2014 | Following a hearing, the NEB approved the Canadian Mainline's 2015 - 2030 Tolls and Tariff Application (the NEB 2014 Decision) which superseded the NEB 2013 Decision. The application reflected components of the LDC Settlement. In 2014, the Canadian Mainline operated under the NEB's decision for the years 2013-2017, which included an approved ROE of 11.5 per cent on deemed common equity of 40 per cent and an incentive mechanism based on total net revenues. |
TCPL Annual information form 2015 | 7 |
Date | Description of development |
First Quarter 2015 | In 2015, the Canadian Mainline began operating under the NEB 2014 Decision. The NEB 2014 Decision included an approved ROE of 10.1 per cent with a possible range of achieved ROE outcomes between 8.7 per cent to 11.5 per cent. This decision also included an incentive mechanism that has both upside and downside risk and a $20 million annual after-tax contribution from us. Toll stabilization is achieved through the continued use of deferral accounts to capture the surplus or shortfall between our revenues and cost of service for each year over the six-year fixed toll term. |
August 2015 | TransCanada announced it had reached an agreement with the eastern LDCs that resolves the LDCs’ issues with Energy East and the Eastern Mainline Project. |
Eastern Mainline Project | |
May 2014 | We filed a project description with the NEB for the Eastern Mainline Project. |
October 2014 | An application was filed with the NEB for the Energy East project and to transfer a portion of the Canadian Mainline from natural gas service to crude oil service. An application was also filed for the Eastern Mainline Project, consisting of new gas facilities in southeastern Ontario required as a result of the proposed transfer of Mainline assets to crude oil service for the Energy east project. |
August 2015 | TransCanada announced it has reached an agreement with eastern LDCs that resolved their issues with Energy East and the Eastern Mainline Project. |
December 2015 | Application amendments were filed that reflect the agreement we announced in August 2015 with eastern LDCs resolving their issues with Energy East and the Eastern Mainline Project. The agreement provides gas consumers in eastern Canada with sufficient natural gas transmission capacity and provides for reduced natural gas transmission costs. The Eastern Mainline Project capital cost is now estimated to be $2.0 billion with the increase in the cost estimate due to the revised project scope resulting from the LDC agreement and updated cost estimates. The Eastern Mainline Project is conditioned on the approval and construction of the Energy East pipeline. |
January 2016 | The Canadian federal government announced interim measures for its review of the Energy East pipeline project. The government announced it will undertake additional consultations with aboriginal groups, help facilitate expanded public input into the NEB, and assess upstream GHG emissions associated with the project. The government will seek a six month extension to the NEB’s legislative review and a three month extension to the legislative time limit for the government’s decision. We are reviewing these changes and will assess the impacts to the Eastern Mainline Project. |
Other Canadian Mainline Expansions | |
November 2014 | In addition to the Eastern Mainline Project, we executed new short haul arrangements in the Eastern Triangle portion of the Canadian Mainline that require new facilities, or modifications to existing facilities. These projects are subject to regulatory approval and, once constructed, will provide capacity needed to meet customer requirements in eastern Canada. |
First Quarter 2016 | In addition to the Eastern Mainline Project, new facilities investments totaling approximately $700 million over the 2016 to 2017 period in the Eastern Triangle portion of the Canadian Mainline are required to meet contractual commitments from shippers. |
ANR Pipeline | |
October 2013 | We concluded a successful binding open season. We executed firm transportation contracts for 350 MMcf/d at maximum tariff rates for 10 years on the ANR Lebanon Lateral Reversal project, entailing modifications to existing facilities. The project substantially increases our ability to receive gas on ANR's Southeast Main Line (SEML) from the Utica/Marcellus shale areas. |
March 2014 | We secured nearly 2.0 Bcf/d of additional firm natural gas transportation commitments for existing and expanded capacity on ANR Pipeline’s SEML. The capacity sales and expansion projects include reversing the Lebanon Lateral in western Ohio, additional compression at Sulphur Springs, Indiana, expanding the Rockies Express pipeline interconnect near Shelbyville, Indiana and 600 MMcf/d of capacity as part of a reversal project on the SEML. Capital costs associated with the ANR System expansions required to bring the additional capacity to market are currently estimated to be US$150 million. The capacity was subscribed at maximum rates for an average term of 23 years with approximately 1.25 Bcf/d of new contracts beginning service in late 2014. These secured contracts on the SEML will move Utica and Marcellus shale gas to points north and south on the system. ANR is also assessing further demand from our customers to transport natural gas from the Utica/Marcellus formation, which is expected to result in incremental opportunities to enhance and expand the system. |
January 2016 | ANR Pipeline filed a Section 4 Rate Case that requests an increase to ANR's maximum transportation rates. Shifts in ANR’s traditional supply sources and markets, necessary operational changes, needed infrastructure updates, and evolving regulatory requirements are driving required investment in facility maintenance, reliability and system integrity as well as an increase in operating costs that have resulted in the current tariff rates not providing a reasonable return on our investment. We will also pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement negotiations. ANR's last rate case filing was more than 20 years ago. |
8 | TCPL Annual information form 2015 |
Date | Description of development |
U.S. Pipelines | |
Sale of GTN Pipeline, Bison Pipeline and Portland Natural Gas Transmission System (PNGTS) to TC PipeLines, LP (TCLP) | |
July 2013 | We sold an additional 45 per cent interest in each of Gas Transmission Northwest LLC (GTN) and Bison Pipeline LLC (Bison) to TCLP for an aggregate purchase price of US$1.05 billion. We continued to hold a 30 per cent direct ownership interest in both pipelines. |
October 2014 | We closed the sale of our remaining 30 per cent interest in Bison to TCLP for cash proceeds of US$215 million. |
April 2015 | We closed the sale of our remaining 30 per cent interest in GTN to TCLP for an aggregate purchase price of US$457 million. Proceeds were comprised of US$246 million in cash, the assumption of US$98 million in proportional GTN debt and US$95 million of new Class B units of TCLP. |
January 2016 | We closed the sale of 49.9 per cent of our total 61.7 per cent interest in PNGTS to TCLP for US$223 million including the assumption of US$35 million of proportional PNGTS debt. |
TC Offshore | |
December 2015 | We entered into an agreement to sell TC Offshore to a third party and expect the sale to close in early 2016. As a result, at December 31, 2015, the related assets and liabilities were classified as held for sale and were recorded at their fair values less costs to sell. This resulted in a pre-tax loss provisions of $125 million recorded in 2015. |
Great Lakes | |
November 2013 | Great Lakes received FERC approval for a rate settlement with its shippers resulting in maximum recourse rates increasing by approximately 21 per cent resulting in a modest increase in revenues derived from its recourse rate contracts. The settlement included a 17 month moratorium through March 2015 and required us to have new rates in effect by January 1, 2018. |
February 2016 | We reduced forecasted cash flows from the reporting unit for the next ten years as compared to those utilized in previous impairment tests. There is a risk that continued reductions in future cash flow forecasts and adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill balance relating to Great Lakes. Our share of the goodwill related to Great Lakes, net of non-controlling interests, was US$386 million at December 31, 2015 (2014 – US$243 million). |
Northern Border | |
January 2013 | Northern Border secured a final settlement agreement with its shippers that the FERC approved in December 2012, effective January 2013. The settlement rates for long haul transportation were approximately 11 per cent lower than 2012 rates and depreciation was lowered from 2.4 to 2.2 per cent. The settlement also included a three year moratorium on filing cases or challenging the settlement rates but Northern Border must initiate another rate proceeding within five years. |
Mexican Pipelines | |
Topolobampo and Mazatlan Pipeline Projects | |
First Quarter 2016 | Permitting, engineering, and construction activities are advancing as planned for these two northwest Mexico pipelines. The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a capacity of 670 MMcf/d and a cost of US$1 billion that will deliver gas to Topolobampo, Sinaloa from interconnects with third party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico. The Mazatlan project is a 413 km (257 miles), 24-inch pipeline running from El Oro to Mazatlan within the state of Sinaloa with a capacity of 200 MMcf/d and an estimated cost of US$400 million. Both projects are supported by 25-year contracts with the CFE and are in their final construction stages with expected in-service dates in late 2016. |
Tuxpan-Tula Pipeline | |
November 2015 | We were awarded the contract to build, own and operate the US$500 million, 36 inch, 250 km (155 miles) Tuxpan-Tula pipeline with a contracted capacity of 886 MMcf/d for 25 years with the CFE. The pipeline will originate in Tuxpan in the state of Veracruz and extend through the states of Puebla and Hidalgo, supplying natural gas to each of those jurisdictions as well as the central region of Mexico. The pipeline will serve new power generating facilities as well as existing power plants that plan to switch from fuel oil to natural gas as their base fuel. Physical construction is expected to begin in 2016 with a planned in-service date in fourth quarter 2017. |
TCPL Annual information form 2015 | 9 |
Date | Description of development |
Tamazunchale Pipeline Extension Project | |
November 2014 | Construction of the US$600 million extension was completed. Delays from the original service commencement date in March 2014 were attributed primarily to archeological findings along the pipeline route. Under the terms of the transportation service agreement, these delays were recognized as a force majeure with provisions allowing for collection of revenue from the original service commencement date. |
Guadalajara | |
First Quarter 2013 | The compressor station went into service. |
International Gas Pipelines | |
Gas-Pacifico/INNERGY Sale | |
November 2014 | We closed the sale of our 30 per cent equity interests in Gas Pacifico/INNERGY at a price of $9 million. This sale marked our exit from the Southern Cone region of South America. |
LNG Pipeline Projects | |
Prince Rupert Gas Transmission | |
January 2013 | We were selected to design, build, own and operate the proposed PRGT pipeline. We were focused on Aboriginal, community, landowner and government engagement as the PRGT advanced through the regulatory process with the Environmental Assessment Office (EAO). We continued to refine our study corridor based on consultation and detailed studies. |
November 2014 | We received an Environmental Assessment Certificate (EAC) from the B.C. EAO. We have submitted our pipeline permit applications to the B.C. Oil and Gas Commission (OGC) for construction of the pipeline. We made significant changes to the project route since first announced, increasing it by 150 km (93 miles) to 900 km (559 miles), taking into account Aboriginal and stakeholder input. We continued to work closely with Aboriginal groups and stakeholders along the proposed route to create and deliver appropriate benefits to all impacted groups. We concluded a benefits agreement with the Nisga’a First Nation to allow 85 km (52 miles) of the proposed natural gas pipeline to run through Nisga'a Lands. |
June 2015 | PNW LNG announced a positive FID for its proposed liquefaction and export facility, subject to two conditions. The first condition, approval by the Legislative Assembly of B.C. of a Project Development Agreement between PNW LNG and the Province of B.C., was satisfied in July 2015. The second condition is a positive regulatory decision on PNW LNG’s environmental assessment by the Government of Canada, which has not yet been received. |
Third Quarter 2015 | We received all remaining permits from the B.C. OGC which completes the eleven permits required to build and operate PRGT. Environmental permits for the project were received in November 2014 from the B.C. EAO. With these permits, PRGT has all of the primary regulatory permits required for the project. We remain on target to begin construction following confirmation of a FID by PNW LNG. The in-service date for PRGT is estimated to be 2020 but will be aligned with PNW LNG’s liquefaction facility timeline. |
February 2016 | We are continuing our engagement with Aboriginal groups and have now signed project agreements with ten First Nation groups along the pipeline route. Project agreements outline financial and other benefits and commitments that will be provided to each First Nation for as long as the project is in service. PRGT is a 900 km (559 miles) natural gas pipeline that will deliver gas from the Montney producing region at an expected interconnect on the NGTL System near Fort St. John, B.C. to PNW LNG's proposed LNG facility near Prince Rupert, B.C. Should the project not proceed, our project costs (including carrying charges) are fully recoverable. |
Coastal GasLink | |
January 2014 | We filed the EAC application with the B.C. EAO. We focused on community, landowner, government and Aboriginal engagement as the project advanced through the regulatory process. The pipeline would be placed in service near the end of the decade, subject to a FID to be made by LNG Canada after obtaining final regulatory approvals. The 670 km (416 miles) pipeline is expected to have an initial capacity of 1.7 Bcf/d and will transport natural gas from the Montney gas producing region near Dawson Creek, B.C. to LNG Canada's proposed LNG export facility near Kitimat, B.C. |
October 2014 | The EAO issued an EAC for Coastal GasLink. In 2014, we also submitted applications to the B.C. OGC for the permits required under the Oil and Gas Activities Act to build and operate Coastal GasLink. |
10 | TCPL Annual information form 2015 |
Date | Description of development |
First Quarter 2016 | We are continuing our engagement with Aboriginal groups along our pipeline route and have now announced long-term project agreements with eleven First Nations. These project agreements outline financial and other benefits and commitments that will be provided to each First Nation for as long as the pipeline remains in service. We also continue to engage with stakeholders along the pipeline route and are progressing detailed engineering and construction planning work to refine the capital cost estimate. In response to feedback received, we have applied for a minor route amendment to the B.C. EAO in order to provide an option in the area of concern. It is anticipated that approval for this route amendment will be received in first quarter 2016. We have received eight of ten pipeline and facilities permits from the B.C. OGC and anticipate receiving the remaining two permits in first quarter 2016. With these permits, Coastal GasLink will hold all of the required primary regulatory permits for the project. The LNG Canada participants have indicated they expect to make a FID later in 2016. We remain optimistic that their project will proceed and our development activities for the Coastal GasLink project remain fully coordinated with their project schedule. Our pipeline in-service date will be scheduled to coincide with the operational requirements of the LNG Canada facility to be built in Kitimat, B.C. Should the project not proceed, our project costs (including carrying charges) are fully recoverable. |
Alaska LNG Project | |
April 2014 | The State of Alaska passed new legislation to provide a framework for us, the three major North Slope producers (the ANS Producers), and the Alaska Gasline Development Corp. (AGDC) to advance the development of an LNG export project. |
June 2014 | We executed an agreement with the State of Alaska to abandon the previous Alaska to Alberta project governance and framework and executed a new precedent agreement where we will act as the transporter of the State’s portion of natural gas under a long-term shipping contract in the Alaska LNG Project. We also entered into a Joint Venture Agreement with the three major ANS Producers and AGDC to commence the pre-front end engineering and design (pre-FEED) phase of Alaska LNG Project. The pre-FEED work was anticipated to take two years to complete with our share of the cost to be approximately US$100 million. The precedent agreement also provided us with full recovery of development costs in the event the project did not proceed. |
November 2015 | We sold our interest in the Alaska LNG project to the State of Alaska. The proceeds of US$65 million from this sale provide a full recovery of costs incurred to advance the project since January 1, 2014 including a carrying charge. With this sale, our involvement in developing a pipeline system for commercializing Alaska North Slope natural gas ceases. |
Date | Description of development |
Keystone Pipeline System | |
January 2014 | We finished constructing the 780 km (485 miles) 36-inch pipeline of the Gulf Coast extension of the Keystone Pipeline System from Cushing, Oklahoma to the U.S. Gulf Coast, and crude oil transportation service on the project began. Average pipeline capacity was 520,000 Bbl/d for the first year of operation. The completion of the Gulf Coast extension in January 2014 expanded the Keystone Pipeline System to a 4,247 km (2,639 miles) pipeline system that transports crude oil from Hardisty, Alberta, to markets in the U.S. Midwest and the U.S. Gulf Coast. |
Fourth Quarter 2015 | We secured additional long term contracts bringing our total contract position up to 545,000 Bbl/d. |
CITGO Sour Lake Pipeline | |
Second Quarter 2015 | We entered into an agreement with CITGO Petroleum (CITGO) to construct a US$65 million pipeline connection between the Keystone Pipeline System to provide access to CITGO’s Sour Lake, Texas terminal, which supplies their 425,000 Bbl/d Lake Charles, Louisiana refinery. The connection is targeted to be operational in fourth quarter 2016. |
Cushing Marketlink | |
September 2014 | Construction was completed. |
Houston Lateral and Terminal | |
Third Quarter 2015 | Construction continued on the 77 km (48 miles) Houston Lateral pipeline and tank terminal which will extend the Keystone Pipeline System to Houston, Texas refineries. The terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are expected to be completed in second quarter 2016. |
TCPL Annual information form 2015 | 11 |
Date | Description of development |
January 2016 | We entered into an agreement with Magellan Midstream Partners L.P. (Magellan) to connect our Houston Terminal to Magellan's Houston and Texas City, Texas delivery system. We will own 50 per cent of this US$50 million pipeline project which will enhance connections for our Keystone Pipeline System to the Houston market. The pipeline is expected to be operational during the first half of 2017, subject to the receipt of all necessary rights-of-way, permits and regulatory approvals. |
Keystone XL | |
January 2013 | The Nebraska Department of Environmental Quality (NDEQ) issued its final evaluation report on our proposed reroute of Keystone XL to the Governor of Nebraska. In January 2013, the Governor of Nebraska approved our proposed reroute. The NDEQ issued its final evaluation report noting that construction and operation of Keystone XL is expected to have minimal environmental impacts in Nebraska. |
March 2013 | The DOS released its Draft Supplemental Environmental Impact Statement for Keystone XL. The impact statement reaffirmed construction of the 830,000 Bbl/d Keystone XL project would not result in any significant impact to the environment. |
January 2014 | The DOS released its Final Supplemental Environmental Impact Statement (FSEIS) for the Keystone XL project. The results included in the report were consistent with previous environmental reviews of Keystone XL. The FSEIS concluded Keystone XL is “unlikely to significantly impact the rate of extraction in the oil sands” and that all other alternatives to Keystone XL are less efficient methods of transporting crude oil, and would result in significantly more GHG emissions, oil spills and risks to public safety. The report initiated the National Interest Determination period of up to 90 days which involves consultation with other governmental agencies and provides an opportunity for public comment. |
February 2014 | A Nebraska district court ruled that the state Public Service Commission, rather than Governor Dave Heineman, had the authority to approve an alternative route through Nebraska for Keystone XL. |
April 2014 | The DOS announced that the national interest determination period had been extended indefinitely to allow them to consider the potential impact of the Nebraska portion of the pipeline route. |
September 2014 | Nebraska’s Attorney General filed an appeal which was heard by the Nebraska State Supreme Court. We filed a certification petition for Keystone XL with the South Dakota Public Utilities Commission (PUC). This certification confirmed that the conditions under which Keystone XL’s original June 2010 PUC construction permit was granted continued to be satisfied. |
January 2015 | The Nebraska State Supreme Court vacated the lower court’s ruling that the law was unconstitutional. As a result, the Governor’s January 2013 approval of the alternate route through Nebraska for Keystone XL remains valid. Landowners have filed lawsuits in two Nebraska counties seeking to enjoin Keystone XL from condemning easements on state constitutional grounds. |
November 2015 | The decision on the Keystone XL Presidential permit application was delayed throughout 2015 by the DOS and was ultimately denied in November 2015. At December 31, 2015, as a result of the denial of the Presidential permit, we evaluated our investment in Keystone XL and related projects, including Keystone Hardisty Terminal, for impairment. As a result of our analysis, we determined that the carrying amount of these assets was no longer recoverable, and recognized a total non-cash impairment charge of $3.7 billion ($2.9 billion aftertax). The impairment charge was based on the excess of the carrying value of $4.3 billion over the fair value of $621 million, which includes $93 million fair value for Keystone Hardisty Terminal. The Keystone Hardisty Terminal remains on hold with an estimated in-service date to be driven by market need. The calculation of this impairment is discussed further in the Other information – Critical accounting estimates section of the MD&A. Also in November 2015, we withdrew our application to the Nebraska Public Service Commission for approval of the route for Keystone XL in the state. The application was initially filed in October 2015. The withdrawal was made without prejudice to potentially refile if we elect to pursue the project. |
January 2016 | On January 5, 2016, the South Dakota PUC accepted Keystone’s certification that it continues to comply with the conditions in its existing 2010 permit authority in the state. On January 6, 2016, we filed a Notice of Intent to initiate a claim under Chapter 11 of NAFTA in response to the U.S. Administration’s decision to deny a Presidential permit for the Keystone XL Pipeline on the basis that the denial was arbitrary and unjustified. Through the NAFTA claim, we are seeking to recover more than US$15 billion in costs and damages that we estimated to have suffered as a result of the U.S. Administration’s breach of its NAFTA obligations. This litigation is in a preliminary stage and the likelihood of success and resulting impact on our financial position or results of operation is unknown at this time. On the same day, we filed a lawsuit in the U.S. Federal Court in Houston, Texas, asserting that the U.S. President’s decision to deny construction of Keystone XL exceeded his power under the U.S. Constitution. The federal court lawsuit does not seek damages, but rather a declaration that the permit denial is without legal merit and that no further Presidential action is required before construction of the pipeline can proceed. We remain supportive of Keystone XL and continue to review our options, including filing a new application for a cross-border permit. |
12 | TCPL Annual information form 2015 |
Date | Description of development |
Energy East Pipeline | |
April 2013 | We announced that we were holding an open season to obtain firm commitments for a pipeline to transport crude oil from western receipt points to eastern Canadian markets. The open season followed a successful expression of interest phase and discussions with prospective shippers. |
August 2013 | We announced that we were moving forward with the 1.1 million Bbl/d Energy East Pipeline as it received approximately 900,000 Bbl/d of firm, long-term contracts in its open season to transport crude oil from western Canada to eastern refineries and export terminals. The project was estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets. We began Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning. |
March 2014 | We filed the project description for the Energy East Pipeline with the NEB. This was the first formal step in the regulatory process to receive the necessary approvals to build and operate the pipeline. |
October 2014 | We filed the necessary regulatory applications for approvals to construct and operate the Energy East Pipeline and terminal facilities with the NEB. Subject to regulatory approvals, the pipeline was anticipated to commence deliveries by the end of 2018. |
April 2015 | We announced that the proposed marine terminal and associated tank terminal in Cacouna, Québec will not be built as a result of the recommended reclassification of the beluga whale, indigenous to the site, as an endangered species. |
November 2015 | Following consultation with stakeholders and shippers, we announced the intention to amend the Energy East application to remove a port in Québec and proceed with a single marine terminal in Saint John, New Brunswick. |
December 2015 | We filed an amendment to the existing project application with the NEB that adjusted the proposed route, scope and capital cost of the project reflecting refinement and scope change including the removal of the port in Québec. The project will continue to serve the three eastern Canadian refineries along the route in Montréal and Québec City, Québec and Saint John, New Brunswick. |
January 2016 | Changes to the project schedule and scope, as reflected in the amendment, contributed to a revised project capital cost of $15.7 billion, excluding the transfer of Canadian Mainline natural gas assets. Of the total long-term shipping commitments for the project of 995,000 Bbl/d, with an average term of 19 years, 725,000 bbl/d designate the Québec refineries, or Saint John, New Brunswick as delivery points. A total of 270,000 Bbl/d remains under contract for delivery to the Québec market, including a Québec based marine terminal and without a Saint John, New Brunswick delivery point. Discussions are ongoing with those shippers to remove the Québec marine terminal from the terms of.their shipping contracts. Subject to regulatory approvals, the pipeline is anticipated to commence deliveries by the end of 2020. However, on January 27, 2016, the Canadian federal government announced interim measures for pipeline reviews, including in respect of the Energy East project. The government announced it will undertake additional consultations with aboriginal groups, help facilitate expanded public input into the NEB and assess Energy East's impact on upstream GHG emissions. The government will seek a six month extension to the NEB’s legislative review and a three month extension to the legislative time limit for the government’s decision which will extend the total review time to 27 months. We are currently reviewing these changes to assess their impact to the project. |
Northern Courier Pipeline | |
April 2013 | We filed a permit application with the Alberta Energy Regulator (AER) after completing the required Aboriginal and stakeholder engagement and associated field work. |
October 2013 | Suncor Energy Inc. (Suncor) announced that Fort Hills Energy Limited Partnership was proceeding with the Fort Hills oil sands mining project and that it expected to begin producing crude oil in 2017. The Northern Courier Pipeline will transport crude oil from the Fort Hills mine site to Suncor’s tank facilities located north of Fort McMurray. |
July 2014 | The AER issued a permit approving our application to construct and operate the Northern Courier Pipeline. Construction has started on the pipeline. |
First Quarter 2016 | Construction continues on the pipeline system to transport bitumen and diluent between the Fort Hills mine site and Suncor terminal located north of Fort McMurray, Alberta. The project is fully underpinned by long term contracts with the Fort Hills partnership. We expect the pipeline system to be ready for service in 2017. |
Heartland Pipeline and TC Terminals | |
May 2013 | We announced we had reached binding long-term shipping agreements to build, own and operate the Heartland Pipeline and TC Terminals projects, and filed a permit application for the terminal facility. In October 2013, we filed a permit application for the pipeline with the AER after completing the required Aboriginal and stakeholder engagement and associated field work. |
February 2014 | The application for the terminal facility was approved by the AER. |
TCPL Annual information form 2015 | 13 |
Date | Description of development |
October 2014 | Construction commenced on the terminal and has since been delayed and the in-service date for the projects will be determined and aligned with industry conditions and our customer's requirements. The Heartland Pipeline is a crude oil pipeline connecting the Edmonton/Heartland, Alberta market region to facilities in Hardisty, Alberta. TC Terminals is a terminal facility in the Heartland industrial area north of Edmonton, Alberta located at the start of the Heartland Pipeline. |
Grand Rapids Pipeline | |
May 2013 | We filed a permit application with the AER for the Grand Rapids Pipeline, a dual 36-inch/20-inch crude oil and diluent pipeline system connecting producing areas northwest of Fort McMurray, Alberta to terminals in the Edmonton/Heartland, Alberta region after completing the required Aboriginal and stakeholder engagement and associated field work. Our partner has also entered into a long-term transportation service contract in support of the Grand Rapids Pipeline. Along with our partner, we will each own 50 per cent of the project and we will operate the system. |
October 2014 | The AER issued a permit approving our application to construct and operate the Grand Rapids Pipeline. Construction is progressing on phase one, which includes a 20-inch pipeline from northern Alberta to Edmonton, Alberta and a 36-inch pipeline between Edmonton and Fort Saskatchewan, Alberta. We anticipate phase one to begin crude oil transportation service in 2017. The construction of phase two, the larger 36-inch pipeline, is currently delayed and the in-service date will be subject to sufficient market demand. We will operate the Grand Rapids Pipeline once complete. |
August 2015 | We announced a joint venture between Grand Rapids and Keyera Corp. for provision of diluent transportation service on the 20-inch pipeline between Edmonton and Fort Saskatchewan, Alberta, which is anticipated to be in service in the second half of 2017. The joint venture will be incorporated into phase one of Grand Rapids and it will provide enhanced diluent supply alternatives to our shippers. |
Upland Pipeline | |
November 2014 | We completed a successful binding open season for the Upland Pipeline. The commercial contracts we have executed for $600 million Upland Pipeline are conditioned on Energy East proceeding. |
April 2015 | We filed an application to obtain a U.S. Presidential permit for the Upland Pipeline. The pipeline will provide crude oil transportation from and between multiple points in North Dakota and interconnect with the Energy East Pipeline System at Moosomin, Saskatchewan. Subject to regulatory approvals, we anticipate the Upland Pipeline to be in service in 2020. The commercial contracts we have executed for Upland Pipeline are conditioned on the Energy East project proceeding. |
January 2016 | We are reviewing the Canadian federal government's interim measures for pipeline reviews and to assess their impact to Upland Pipeline. |
Liquids Marketing | |
2015 | We established a liquids marketing business to expand into other areas of the liquids business value chain. The liquids marketing business will generate revenue by capitalizing on asset utilization opportunities by entering into short-term or long-term pipeline or storage terminal capacity contracts. Volatility in commodity prices and changing market conditions could impact the value of those capacity contracts. Availability of alternative pipeline systems that can deliver into the same areas can also impact contract value. The liquids marketing business complies with our risk management polices which are described in the Other information - Risks and risk management section of the MD&A. |
14 | TCPL Annual information form 2015 |
Date | Description of development |
Canadian Power | |
Alberta Greenhouse Gas Emissions | |
June 2015 | The Alberta government announced a renewal and change to the SGER in Alberta. Since 2007, under the SGER, established industrial facilities with GHG emissions above a certain threshold are required to reduce their emissions by 12 per cent below an average intensity baseline and a carbon levy of $15 per tonne is placed on emissions above this target. The changed regulations include an increase in the emissions reductions target to 15 per cent in 2016 and 20 per cent in 2017, along with an increase in the carbon levy to $20 per tonne in 2016 and $30 per tonne in 2017. Starting in 2018, coal-fired generators will pay $30 per tonne of CO2 on emissions above what Alberta’s cleanest natural gas-fired plant would emit to produce an equivalent amount of electricity. While our Sundance and Sheerness PPAs are subject to this regulation, our inventory of carbon offset credits will mitigate some of these increased costs. The remaining compliance costs are expected to be somewhat recovered through increased market pricing but the full extent is not known at this time. |
Napanee | |
January 2015 | We began construction activities on a 900 MW natural gas-fired power plant at Ontario Power Generation’s Lennox site in eastern Ontario in the town of Greater Napanee. We expect to invest approximately $1.0 billion in the Napanee facility during construction and commercial operations are expected to begin in late-2017 or early-2018. Production from the facility is fully contracted with the IESO. |
Bécancour | |
June 2013 | Hydro-Québec Distribution (Hydro-Québec) notified us that it would exercise its option to extend the agreement to suspend all electricity generation from the Bécancour power plant through 2014. Hydro-Québec had notified us that it would exercise its option to extend the agreement to suspend all electricity generation from the Bécancour power plant through 2013. Under the original agreement, Hydro-Québec had the option to extend the suspension on an annual basis until such time as regional electricity demand levels recover. |
December 2013 | We entered into an amendment to the original suspension agreement with Hydro-Québec to further extend suspension of generation through to the end of 2017. Under the amendment, Hydro-Québec continued to have the option (subject to certain conditions) to further extend the suspension past 2017. The amendment also includes revised provisions intended to reduce Hydro-Québec’s payments to us for Bécancour's natural gas transportation costs during the suspension period, although we retain our ability to recover our full capacity costs under the Electricity Supply Contract with Hydro-Québec while the facility is suspended. |
May 2014 | We received final approval from the Régie de l’énergie for the December 2013 amendment to the original suspension agreement with Hydro-Québec. In addition, Hydro-Québec exercised its option in the amended suspension agreement to extend suspension of all electricity generation to the end of 2017, and requested further suspension of generation to the end of 2018. |
August 2015 | We executed an agreement with Hydro-Québec to amend Bécancour's electricity supply contract. The amendment allows Hydro-Québec to dispatch up to 570 MW of firm peak winter capacity from the Bécancour facility for a term of 20 years commencing in December 2016. Annual payments received for this new service will be incremental to existing capacity payments earned under the agreement. In October 2015, the Régie de l’énergie approved the amended contract. We continue to receive capacity payments while generation is suspended. |
Bruce Power | |
April 2013 | Bruce Power announced that it had reached an agreement with the Ontario Power Authority to extend the Bruce B floor price through to the end of the decade, which is expected to coincide with the 2019 and 2020 end of life dates for the Bruce B units. |
April 2013 | Bruce Power returned Bruce A Unit 4 to service after completing an expanded life extension outage investment program, which began in August 2012. It is anticipated that this investment will allow Bruce A Unit 4 to operate until at least 2021. |
March 2014 | Cameco Corporation sold its 31.6 per cent limited partnership interest in Bruce B to BPC Generation Infrastructure Trust. We maintain an option to increase our Bruce B ownership percentage. |
TCPL Annual information form 2015 | 15 |
Date | Description of development |
Fourth Quarter 2014 | New Canadian federal legislation is expected to come into force in 2015 respecting the determination of liability and compensation for a nuclear incident in Canada resulting in personal injuries and damages. This proposed legislation will replace existing legislation which currently provides that the licensed operator of a nuclear facility has absolute and exclusive liability and limits the liability to a maximum of $75 million. The proposed new law is fundamentally consistent with the existing regime although the maximum liability will increase to $650 million and increase in increments over three years to a maximum of $1 billion. The operator will also be required to maintain financial assurances such as insurance in the amount of the maximum liability. Our indirect subsidiary owns 50 per cent of the common shares of Bruce Power Inc., the licensed operator of Bruce Power, and as such Bruce Power Inc. is subject to this liability in the event of an incident as well as the legislation’s other requirements. |
December 2015 | Bruce Power entered into an agreement with the IESO to extend the operating life of the facility to the end of 2064. This new agreement represents an extension and material amendment to the earlier agreement that led to the refurbishment of Units 1 and 2 at the site. The amended agreement is effective January 1, 2016 and allows Bruce Power to immediately invest in life extension activities for Units 3 through 8. Our estimated share of investment in the Asset Management program to be completed over the life of the agreement is approximately $2.5 billion (2014 dollars). Our estimated share of investment in the Major Component Replacement work that is expected to begin in 2020 is approximately $4 billion (2014 dollars). Under certain conditions, Bruce Power and the IESO can elect to not proceed with the remaining Major Component Replacement investments should the cost exceed certain thresholds or prove to not provide sufficient economic benefits. The agreement has been structured to account for changing cost inputs over time, including ongoing operating costs and additional capital investments. Beginning in 2016, Bruce Power receives a uniform price of $65.73 per MWh for all units. This price will be adjusted over the term of the agreement to incorporate incremental capital investment and cost changes. In connection with this opportunity, we exercised our option to acquire an additional 14.89 per cent ownership interest in Bruce B for $236 million from the Ontario Municipal Employees Retirement System. Subsequent to this acquisition, Bruce A and Bruce B were merged to form a single partnership structure. In 2015, we recognized a $36 million charge, representing our proportionate share, on the retirement of Bruce Power debt in conjunction with this merger. We now hold a 48.5 per cent interest in this newly merged partnership structure. |
Cancarb Limited and Cancarb Waste Heat Facility | |
January 2014 | We announced we had reached an agreement for the sale of Cancarb Limited, our thermal carbon black facility, and its related power generation facility. |
April 2014 | The sale of Cancarb Limited and its related power generation facility closed for gross proceeds of $190 million. We recognized a gain of $99 million, net of tax, in second quarter 2014. |
Ontario Solar | |
June 2013 | We completed the acquisition of the first facility for $55 million as per our December 2011 agreement, pursuant to which we agreed to buy Ontario solar generation facilities with combined capacity of 86 MW from Canadian Solar Solutions Inc. (Canadian Solar) for approximately $500 million. Under the terms of the agreement, Canadian Solar will develop and build each of the nine solar facilities using photovoltaic panels. We buy each facility once construction and acceptance testing are complete and commercial operation begins. All power produced by the solar facilities is currently or will be sold under 20-year FIT contracts with the IESO. |
September 2013 | We completed the acquisition of two additional solar facilities for $99 million. |
December 2013 | We completed the acquisition of an additional solar facility for $62 million. |
September 2014 | We completed the acquisition of three additional solar facilities for $181 million. |
December 2014 | We acquired an additional solar facility for $60 million. Our total investment in the eight solar facilities is $457 million. |
Alberta PPAs | |
March 2016 | We announced plans to terminate our Alberta PPAs which affects the Sheerness, Sundance A and Sundance B PPAs. As a result of our decision to terminate the PPAs, we expect to record a non-cash charge of approximately $235 million pre-tax ($175 million after-tax) which represents the remaining net book value associated with our original investment in the PPAs. |
U.S. Power | |
Ravenswood | |
September 2014 | The 972 MW Unit 30 at the Ravenswood Generating Station experienced an unplanned outage. |
May 2015 | The Ravenswood Generating Station returned to service after the September 2014 unplanned outage which resulted from a problem with the generator associated with the high pressure turbine. Insurance recoveries for this event are expected to be received in 2016. As a result of the expected insurance recoveries, net of deductibles, the Unit 30 unplanned outage is not expected to have a significant impact on our earnings although the recording of earnings will not coincide with lost revenues due to timing of the insurance proceeds. |
16 | TCPL Annual information form 2015 |
Date | Description of development |
Ironwood | |
February 2016 | We acquired the 778 MW Ironwood natural gas fired, combined cycle power plant located in Lebanon, Pennsylvania from Talen Energy Corporation for US$657 million before post closing adjustments. The Ironwood power plant delivers energy into the PJM power market and will provide us with a solid platform from which to continue to grow our wholesale, commercial and industrial customer base in this market area. |
New York Power Business | |
January 2014 | Capacity prices in the New York market are established through a series of forward auctions and utilize a demand curve administered price for purposes of setting the monthly spot price. The demand curve, among other inputs, uses assumptions with respect to the expected cost of the most likely peaking generation technology applicable to new entrants to the market. In January 2014, the FERC accepted a new rate for the demand curve that was filed by the New York Independent System Operator as part of its triennial Demand Curve Reset (DCR) process. The filing changed the generation technology used in the DCR versus that used during the last reset process for New York City Zone J where Ravenswood operates. Average New York Zone J spot capacity prices were approximately 27 per cent higher in 2014 than in 2013. The increase in spot prices and the impact of hedging activities resulted in higher realized capacity prices in New York in 2014. Average New York Zone J spot capacity prices were approximately 18 per cent lower in 2015 than in 2014. The decrease in spot prices and the impact of hedging activities, resulted in lower realized capacity prices in New York in 2015. The lower spot capacity prices were primarily due to increased available operational supply in New York City's Zone J market. In 2014 we disclosed that the FERC announced a decision affecting future capacity auctions in New England Power Pool (NEPOOL) which we thought may potentially improve capacity price conditions in 2018 and beyond. Since the announcement, capacity prices have improved in 2018 and beyond for our assets that are located in NEPOOL. |
Natural Gas Storage | |
April 2014 | We sold out interest in the Alaska LNG project to the State of Alaska. The proceeds from the sale provide a full recovery of costs incurred to advance the project since January 1, 2014 including a carrying charge. With this sale, our involvements in developing pipeline system for commercializing the Alaska North Slope natural gas ceases. |
TCPL Annual information form 2015 | 17 |
Revenues from operations (millions of dollars) | 2015 | 2014 | ||
Natural Gas Pipelines | ||||
Canada – Domestic | $2,848 | $2,672 | ||
Canada – Export1 | $829 | $881 | ||
United States | $1,447 | $1,163 | ||
Mexico | $259 | $197 | ||
$5,383 | $4,913 | |||
Liquids Pipelines | ||||
Canada – Domestic | — | — | ||
Canada – Export1 | $458 | $432 | ||
United States | $1,421 | $1,115 | ||
$1,879 | $1,547 | |||
Energy2 | ||||
Canada – Domestic | $1,029 | $1,349 | ||
Canada – Export1 | $5 | $1 | ||
United States | $3,004 | $2,375 | ||
$4,038 | $3,725 | |||
Total revenues3 | $11,300 | $10,185 |
1 | Exports include pipeline revenues attributable to Canadian Pipeline and power deliveries to U.S. markets. |
2 | Revenues include sales of natural gas. |
3 | Revenues are attributed to countries based on country of origin of product or service. |
Length | Description | Effective ownership | |||||
Canadian pipelines | |||||||
NGTL System | 24,544 km (15,251 miles) | Receives, transports and delivers natural gas within Alberta and B.C., and connects with the Canadian Mainline, Foothills system and third-party pipelines | 100 | % | |||
Canadian Mainline | 14,114 km (8,770 miles) | Transports natural gas from the Alberta/Saskatchewan border and the Ontario/U.S. border to serve eastern Canada and interconnects to the U.S. | 100 | % | |||
Foothills | 1,241 km (771 miles) | Transports natural gas from central Alberta to the U.S. border for export to the U.S. Midwest, Pacific northwest, California and Nevada | 100 | % |
18 | TCPL Annual information form 2015 |
Length | Description | Effective ownership | |||||
Trans Québec & Maritimes (TQM) | 572 km (355 miles) | Connects with Canadian Mainline near the Ontario/Québec border to transport natural gas to the Montréal to Québec City corridor, and connects with the Portland pipeline system that serves the northeast U.S. | 50 | % | |||
U.S. pipelines | |||||||
ANR Pipeline | 15,109 km (9,388 miles) | Transports natural gas from supply basins to markets throughout the mid-west and south to the Gulf of Mexico. | 100 | % | |||
ANR Storage | 250 Bcf | Provides regulated underground natural gas storage service from facilities located in Michigan | |||||
Bison | 488 km (303 miles) | Transports natural gas from the Powder River Basin in Wyoming to Northern Border in North Dakota. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP | 28 | % | |||
GTN | 2,216 km (1,377 miles) | Transports natural gas from the WCSB and the Rocky Mountains to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP | 28 | % | |||
Great Lakes | 3,404 km (2,115 miles) | Connects with the Canadian Mainline near Emerson, Manitoba and St Clair, Ontario, plus interconnects with ANR at Crystal Falls and Farwell in Michigan, to transport natural gas to eastern Canada and the U.S. upper Midwest. We effectively own 66.6 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 28 per cent interest in TC PipeLines, LP | 66.6 | % | |||
Iroquois | 669 km (416 miles) | Connects with Canadian Mainline near Waddington, New York to deliver natural gas to customers in the U.S. northeast | 44.5 | % | |||
North Baja | 138 km (86 miles) | Transports natural gas between Arizona and California, and connects with a third-party pipeline on the California/Mexico border. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP | 28 | % | |||
Northern Border | 2,264 km (1,407 miles) | Transports WCSB and Rockies natural gas with connections to Foothills and Bison to U.S. Midwest markets. We effectively own 14 per cent of the system through our interest in TC PipeLines, LP | 14 | % | |||
PNGTS | 475 km (295 miles) | Connects with TQM near East Hereford, Québec to deliver natural gas to customers in the U.S. northeast. We effectively own 25.8 per cent of the system through the combination of 11.8 per cent direct ownership and our 28 per cent interest in TC PipeLines, LP. Prior to January 1, 2016 we had direct ownership of 61.7 per cent. | 25.8 | % | |||
Tuscarora | 491 km (305 miles) | Transports natural gas from GTN to Malin, Oregon to markets in northeastern California and northwestern Nevada. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP | 28% | ||||
TC Offshore1 | 958 km (595 miles) | Gathers and transports natural gas within the Gulf of Mexico with subsea pipeline and seven offshore platforms to connect in Louisiana with our ANR Pipeline system. | 100% | ||||
Mexican pipelines | |||||||
Guadalajara | 315 km (196 miles) | Transports natural gas from Manzanillo, Colima to Guadalajara, Jalisco | 100 | % | |||
Tamazunchale | 365 km (227 miles) | Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potosi and on to El Sauz, Queretaro | 100 | % | |||
Under construction | |||||||
Mazatlan Pipeline | 413 km* (257 miles) | To deliver natural gas from El Oro to Mazatlan, Sinaloa in Mexico. Will connect to the Topolobampo Pipeline at El Oro | 100 | % | |||
Topolobampo Pipeline | 530 km* (329 miles) | To deliver natural gas to Topolobampo, Sinaloa, from interconnects with third-party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico | 100 | % |
TCPL Annual information form 2015 | 19 |
Length | Description | Effective ownership | |||||
Tuxpan-Tula Pipeline | 250 km* (155 miles) | The pipeline will originate in Tuxpan in the state of Veracruz and extend through the states of Puebla and Hidalgo, supplying natural gas to CFE combined-cycle power generating facilities in each of those jurisdictions as well as to the central and western regions of Mexico. | 100% | ||||
NGTL 2016/17 Facilities | 540 km* (336 miles) | An expansion program comprised of 21 integrated projects of pipes, compression and metering to meet new incremental firm service requests received in 2014 on the NGTL System and expected to be completed between 2016 and 2018. | 100% | ||||
In development | |||||||
Coastal GasLink | 670 km* (416 miles) | To deliver natural gas from the Montney gas producing region at an expected interconnect on NGTL near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C. | 100% | ||||
Prince Rupert Gas Transmission | 900 km* (559 miles) | To deliver natural gas from the North Montney gas producing region at an expected interconnect on NGTL near Fort St. John, B.C. to the proposed Pacific Northwest LNG facility near Prince Rupert, B.C. | 100% | ||||
North Montney Mainline | 301 km* (187 miles) | An extension of the NGTL System to receive natural gas from the North Montney gas producing region and connect to NGTL's existing Groundbirch Mainline and the proposed Prince Rupert Gas Transmission project | 100% | ||||
Merrick Mainline | 260 km* (161 miles) | To deliver natural gas from NGTL's existing Groundbirch Mainline near Dawson Creek, B.C. to its end point near the community of Summit Lake, B.C. | 100% | ||||
Eastern Mainline Project | 279 km* (173 miles) | Pipeline and compression facilities expected to be added in the Eastern Triangle of the Canadian Mainline to meet the requirements of the existing shippers as well as new firm service requirements following the conversion of components of the Mainline to facilitate the Energy East project. | 100% | ||||
NGTL 2018 Facilities | 88 km* (55 miles) | An expansion program comprised of multiple projects of 20- to 48-inch diameter pipelines, one new compressor unit and multiple meter stations to meet new incremental firm service requests received in 2015 on the NGTL System and expected to be completed in 2018. | 100% | ||||
* Final pipe lengths are subject to changes during construction and/or final design considerations. |
1 | As at December 31, 2015, TC Offshore was classified as Assets held for sale. See the Natural Gas Pipelines – Significant events section of the MD&A for further information. |
20 | TCPL Annual information form 2015 |
Length | Description | Ownership | |||||
Liquids pipelines | |||||||
Keystone Pipeline System | 4,247 km (2,639 miles) | Transports crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka Illinois, Cushing, Oklahoma, and Port Arthur, Texas | 100 | % | |||
Cushing Marketlink and Terminal | Terminal and pipeline facilities to transport crude oil from the market hub at Cushing, Oklahoma to the Port Arthur, Texas refining market on facilities that form part of the Keystone Pipeline System | 100 | % | ||||
Under construction | |||||||
Houston Lateral and Houston Terminal | 77 km (48 miles) | To extend the Keystone Pipeline System to the Houston, Texas refining market | 100 | % | |||
Grand Rapids Pipeline | 460 km (287 miles) | To transport crude oil and diluent between the producing area northwest of Fort McMurray, Alberta and the Edmonton/Heartland, Alberta market region | 50 | % | |||
Northern Courier Pipeline | 90 km (56 miles) | To transport bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta | 100 | % | |||
In development | |||||||
Bakken Marketlink | To transport crude oil from the Williston Basin producing region in North Dakota and Montana to Cushing, Oklahoma on facilities that form part of Keystone XL | 100 | % | ||||
Keystone Hardisty Terminal | Crude oil terminal located at Hardisty, Alberta, providing western Canadian producers with crude oil batch accumulation tankage and access to the Keystone Pipeline System | 100 | % | ||||
Keystone XL | 1,897 km (1,179 miles) | To transport crude oil from Hardisty, Alberta to Steele City, Nebraska to expand capacity of the Keystone Pipeline System | 100 | % | |||
Heartland Pipeline and TC Terminals | 200 km (125 miles) | Terminal and pipeline facilities to transport crude oil from the Edmonton/Heartland, Alberta region to facilities in Hardisty, Alberta | 100 | % | |||
Energy East Pipeline | 4,600 km (2,850 miles) | To transport crude oil from western Canada to eastern Canadian refineries and export markets | 100 | % | |||
Upland Pipeline | 460 km (285 miles) | To transport crude oil from, and between, multiple points in North Dakota and interconnect with the Energy East Pipeline at Moosomin, Saskatchewan | 100 | % |
TCPL Annual information form 2015 | 21 |
22 | TCPL Annual information form 2015 |
Generating capacity (MW) | Type of fuel | Description | Location | Ownership | |||||||
Canadian Power 8,571 MW of power generation capacity (including facilities under construction) | |||||||||||
Western Power 2,609 MW of power supply in Alberta and the western U.S. | |||||||||||
Bear Creek | 80 | natural gas | Cogeneration plant | Grande Prairie, Alberta | 100 | % | |||||
Carseland | 80 | natural gas | Cogeneration plant | Carseland, Alberta | 100 | % | |||||
Coolidge | 575 | natural gas | Simple-cycle peaking facility | Coolidge, Arizona | 100 | % | |||||
Mackay River | 165 | natural gas | Cogeneration plant | Fort McMurray, Alberta | 100 | % | |||||
Redwater | 40 | natural gas | Cogeneration plant | Redwater, Alberta | 100 | % | |||||
Sheerness PPA | 756 | coal | Output contracted under PPA | Hanna, Alberta | 100 | % | |||||
Sundance A PPA | 560 | coal | Output contracted under PPA | Wabamun, Alberta | 100 | % | |||||
Sundance B PPA (Owned by ASTC Power Partnership1) | 3532 | coal | Output contracted under PPA | Wabamun, Alberta | 50 | % | |||||
Eastern Power 2,939 MW of power generation capacity (including facilities under construction) | |||||||||||
Bécancour | 550 | natural gas | Cogeneration plant | Trois-Rivières, Québec | 100 | % | |||||
Cartier Wind | 3652 | wind | Five wind power projects | Gaspésie, Québec | 62 | % | |||||
Grandview | 90 | natural gas | Cogeneration plant | Saint John, New Brunswick | 100 | % | |||||
Halton Hills | 683 | natural gas | Combined-cycle plant | Halton Hills, Ontario | 100 | % | |||||
Portlands Energy | 2752 | natural gas | Combined-cycle plant | Toronto, Ontario | 50 | % | |||||
Ontario Solar | 76 | solar | Eight solar facilities | Southern Ontario and New Liskeard, Ontario | 100 | % | |||||
Bruce Power 3,023 MW of power generation capacity | |||||||||||
Bruce Power | 3,0232 | nuclear | Eight operating reactors | Tiverton, Ontario | 48.5 | % |
TCPL Annual information form 2015 | 23 |
Generating capacity (MW) | Type of fuel | Description | Location | Ownership | ||||||||||||||||
U.S. Power 4,533 MW of power generation capacity | ||||||||||||||||||||
Kibby Wind | 132 | wind | Wind farm | Kibby and Skinner Townships, Maine | 100 | % | ||||||||||||||
Ocean State Power | 560 | natural gas | Combined-cycle plant | Burrillville, Rhode Island | 100 | % | ||||||||||||||
Ravenswood | 2,480 | natural gas and oil | Multiple-unit generating facility using dual fuel-capable steam turbine, combined-cycle and combustion turbine technology | Queens, New York | 100 | % | ||||||||||||||
TC Hydro | 583 | hydro | 13 hydroelectric facilities, including stations and associated dams and reservoirs | New Hampshire, Vermont and Massachusetts (on the Connecticut and Deerfield rivers) | 100 | % | ||||||||||||||
Ironwood3 | 778 | natural gas | Combined-cycle plant | Lebanon, Pennsylvania | 100 | % | ||||||||||||||
Unregulated natural gas storage 118 Bcf of non-regulated natural gas storage capacity | ||||||||||||||||||||
CrossAlta | 68 Bcf | Underground facility connected to the NGTL System | Crossfield, Alberta | 100 | % | |||||||||||||||
Edson | 50 Bcf | Underground facility connected to the NGTL System | Edson, Alberta | 100 | % | |||||||||||||||
Under construction | ||||||||||||||||||||
Napanee | 900 | natural gas | Combined-cycle plant | Greater Napanee, Ontario | 100 | % |
1 | We have a 50 per cent interest in ASTC Power Partnership, which has a PPA for production from the Sundance B power generating facilities. |
2 | Our share of power generation capacity. |
3 | Acquired February 1, 2016. |
Type of contract | With | Expires | ||||
Sheerness PPA | Power purchased under a 20-year PPA | ATCO Power and TransAlta Utilities Corporation | 2020 | |||
Sundance A PPA | Power purchased under a 20-year PPA | TransAlta Utilities Corporation | 2017 | |||
Sundance B PPA | Power purchased under a 20-year PPA (own 50 per cent through the ASTC Power Partnership) | TransAlta Utilities Corporation | 2020 |
Type of contract | With | Expires | ||||
Coolidge | Power sold under a 20-year PPA | Salt River Project Agricultural Improvements & Power District | 2031 |
24 | TCPL Annual information form 2015 |
Type of contract | With | Expires | ||||
Bécancour1,2 | 20-year PPA and tolling agreement Steam sold to an industrial customer | Hydro-Québec | 2036 | |||
Cartier Wind | 20-year PPA | Hydro-Québec | 2026-2032 | |||
Grandview | 20-year tolling agreement to buy 100 per cent of heat and electricity output | Irving Oil | 2024 | |||
Halton Hills | 20-year Clean Energy Supply contract | IESO | 2030 | |||
Portlands Energy | 20-year Clean Energy Supply contract | IESO | 2029 | |||
Ontario Solar3 | 20-year FIT contracts | IESO | 2032-2034 |
1 | Power generation has been suspended since 2008. We continue to receive capacity payments while generation is suspended. |
2 | In August 2015, we executed an agreement with Hydro-Québec to amend Bécancour's electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Bécancour facility for a term of 20 years commencing in December 2016. Annual tolling payments received for this new service will be incremental to existing capacity payments earned under the agreement and will expire in 2036. The existing capacity payments terminate in 2026. |
3 | We acquired four facilities in 2013 and an additional four facilities in 2014. |
Type of contract | With | Expires | ||||
Napanee1 | 20-year Clean Energy Supply contract | IESO | 20 years from in-service date |
1 | Expected in-service date is between late 2017 and early 2018. |
TCPL Annual information form 2015 | 25 |
Calgary (includes U.S. employees working in Canada) | 2,800 |
Western Canada (excluding Calgary) | 474 |
Eastern Canada | 302 |
Houston (includes Canadian employees working in the U.S.) | 491 |
U.S. Midwest | 439 |
U.S. Northeast | 424 |
U.S. Southeast/Gulf Coast (excluding Houston) | 326 |
U.S. West Coast | 74 |
Mexico and South America | 182 |
Total | 5,512 |
• | Planning: risk and regulatory assessment, objectives and targets, and structure and responsibility |
• | Implementing: development and implementation of programs, plans, procedures and practices aimed at operational risk management |
• | Reporting: document and records management, communication and reporting, and |
• | Action: ongoing audit and review of HSE performance. |
• | overall HSE corporate governance and performance |
• | operational performance and preventive maintenance metrics |
• | asset integrity programs |
• | security and emergency preparedness, incident response and evaluation |
• | people and process safety performance metrics, and |
• | developments in and compliance with applicable legislation and regulations. |
26 | TCPL Annual information form 2015 |
TCPL Annual information form 2015 | 27 |
2015 | 2014 | 2013 | |
Dividends declared on common shares1 | $1.89 | $1.75 | $1.74 |
1 | TCPL dividends on its common shares are declared in an amount equal to the aggregate cash dividend paid by TransCanada to its public shareholders. The amounts presented reflect the aggregate amount divided by the total outstanding common shares of TCPL. |
28 | TCPL Annual information form 2015 |
Date Issued | Issue price per $1,000 principal amount of notes | Aggregate issue price | Maturity date |
January 12, 2015 | US$996.84 | US$498,420,000 | January 12, 2018 |
January 12, 2015 | US$1,000.00 | US$250,000,000 | January 12, 2018 |
March 31, 20151 | US$1,000.00 | US$750,000,000 | March 31, 2045 |
May 20, 2015 | US$1,000.00 | US$750,000,000 | May 20, 2075 |
July 17, 2015 | $998.73 | $749,047,500 | July 17, 2025 |
October 6, 2015 | $985.82 | $394,328,000 | November 15, 2041 |
November 9, 2015 | US$999.59 | US$999,590,000 | November 9, 2017 |
January 27, 2016 | US$997.17 | US$398,868,000 | January 15, 2019 |
January 27, 2016 | US$995.81 | US$846,438,500 | January 15, 2026 |
1 | TCPL's Formosa Bonds. |
TCPL Annual information form 2015 | 29 |
DBRS | Moody's | S&P | ||
Senior unsecured debt Debentures Medium-term notes | A (low) A (low) | A3 A3 | A- A- | |
Junior subordinated notes | BBB | Baa1 | BBB | |
TransCanada Trust-Subordinated Notes | Not rated | Baa2 | BBB | |
Preferred shares | Pfd-2 (low) | Baa2 | P-2 | |
Commercial paper | R-1 (low) | P-2 | A-2 | |
Trend/rating outlook | Stable | Stable | Stable |
30 | TCPL Annual information form 2015 |
Date | Number of TCPL common shares | Price per TCPL common share | Aggregate issuance price |
January 20, 2014 | 9,053,497 | $48.60 | $440,000,000 |
April 28, 2014 | 13,310,984 | $50.71 | $675,000,000 |
TCPL Annual information form 2015 | 31 |
Name and place of residence | Principal occupation during the five preceding years | Director since | ||
Kevin E. Benson Calgary, Alberta Canada | Corporate director. Director, Calgary Airport Authority from January 2010 to December 2013. | 2005 | ||
Derek H. Burney1, O.C. Ottawa, Ontario Canada | Senior strategic advisor, Norton Rose Fulbright (law firm). Chair, Garda World International's (risk management and security services) Advisory Board since April 2008. Advisory Board member, Paradigm Capital Inc. (investment dealer) since May 2011. Chair, Canwest Global Communications Corp. (media and communications) from August 2006 (director since April 2005) to October 2010. | 2005 | ||
The Hon. Paule Gauthier, P.C., O.C., O.Q., Q.C. Québec, Québec Canada | Senior Partner, Stein Monast L.L.P. (law firm). Director, Metro Inc. (food retail) since January 2001. Director, Royal Bank of Canada (chartered bank) from October 1991 to March 2014 and Chair, RBC Dexia Investors Trust until October 2011. | 2002 | ||
Russell K. Girling2 Calgary, Alberta Canada | President and Chief Executive Officer, TransCanada since July 2010. Chief Operating Officer from July 2009 to June 2010 and President, Pipelines from June 2006 to June 2010. Director, Agrium Inc. (agricultural) since May 2006. | 2010 | ||
S. Barry Jackson3 Calgary, Alberta Canada | Corporate director. Chair of the Board, TransCanada since April 2005. Director, WestJet Airlines Ltd. (airline) since February 2009 and Laricina Energy Ltd. (oil and gas, exploration and production) since December 2005. Director, Nexen Inc. (Nexen) (oil and gas, exploration and production) from 2001 to June 2013, Chair of the board, Nexen from 2012 to June 2013. | 2002 | ||
John E. Lowe Houston, Texas U.S.A. | Chairman of the Board of Directors, Apache Corporation (Apache) (oil and gas) since May 2015. Senior Adviser at Tudor Pickering, Holt & Co. LLC (energy investment and merchant banking) since September 2012. Director, Phillips 66 Company (energy infrastructure) since May 2012. Director, Apache from July 2013 to May 2015. Director, Agrium Inc. (agriculture) from May 2010 to August 2015. Director, DCP Midstream LLC and DCP Midstream GP, LLC (energy infrastructure) from October 2008 to April 2012. Director, Chevron Phillips Chemical Co. LLC (global petrochemicals) from October 2008 to January 2011. | 2015 | ||
Paula Rosput Reynolds Seattle, Washington U.S.A. | President and Chief Executive Officer, PreferWest, LLC (business advisory group) since October 2009. Director, BP p.l.c. (oil and gas) since May 2015. Director, BAE Systems plc. (aerospace, defence, information security) since April 2011. Director, Delta Air Lines, Inc. (airline) from August 2004 to June 2015. Director, Anadarko Petroleum Corporation (oil and gas, exploration and production) from August 2007 to May 2014. | 2011 | ||
John Richels Nichols Hills, Oklahoma U.S.A. | Corporate Director. Vice Chair, Devon Energy Corporation (Devon) (oil and gas, exploration and production, energy infrastructure) since December 2014 and Director since June 2007. Chairman of EnLink Midstream, LLC and EnLink Midstream Partner, LP (energy infrastructure) since March 2014. Director, BOK Financial Corporation (financial services) since January 2013. Chairman, American Exploration and Production Council since May 2012. Former Vice-Chairman of the board of governors, Association of Petroleum Producers. | 2013 | ||
Mary Pat Salomone4 Naples, Florida U.S.A. | Corporate director. Director, Intertape Polymer Group (manufacturing) since November 2015. Senior Vice-President and Chief Operating Officer, The Babcock & Wilcox Company (B&W) (energy infrastructure) from January 2010 to June 2013. Director, United States Enrichment Corporation (basic materials, nuclear) from December 2011 to October 2012. | 2013 | ||
D. Michael G. Stewart Calgary, Alberta Canada | Corporate director. Director, Pengrowth Energy Corporation (oil and gas, exploration and production) since December 2010. Director, and Audit and Governance committee Chair, Canadian Energy Services & Technology Corp. (chemical, oilfield services) since January 2010. Director, Northpoint Resources Ltd. (oil and gas, exploration and production) from July 2013 to February 2015. Director, C&C Energia Ltd. (oil and gas) from May 2010 to December 2012. | 2006 | ||
Siim A. Vanaselja Westmount, Québec Canada | Corporate Director. Director, Great-West Lifeco Inc. since May 2014. Director and Audit committee Chair, Maple Leaf Sports and Entertainment Ltd. (sports, property management) since August 2012. Executive Vice-President and Chief Financial Officer, BCE Inc. and Bell Canada (telecommunications and media) from January 2001 to June 2015. | 2014 | ||
Richard E. Waugh Calgary, Alberta Canada | Corporate director. Former Deputy Chairman of the Bank of Nova Scotia (Scotiabank) (chartered bank) until January 2014. President and Chief Executive Officer, Scotiabank from March 2003 to November 2013. Director, Catalyst Inc. (non-profit) from February 2007 to November 2013 and Chair, Catalyst Canada Inc. Advisory Board from February 2007 to October 2013. | 2012 |
32 | TCPL Annual information form 2015 |
1 | Canwest Global Communications Corp. (Canwest) voluntarily entered into the Companies’ Creditors Arrangement Act (CCAA) and obtained an order from the Ontario Superior Court of Justice (Commercial Division) to start proceedings on October 6, 2009. Although no cease trade orders were issued, Canwest shares were de-listed by the TSX after the filing and started trading on the TSX Venture Exchange. Canwest emerged from CCAA protection and Postmedia Network acquired its newspaper business on July 13, 2010 while Shaw Communications Inc. acquired its broadcast media business on October 27, 2010. Mr. Burney ceased to be a director of Canwest on October 27, 2010. |
2 | As President and CEO of TransCanada, Mr. Girling is not a member of any Board Committees, but is invited to attend committee meetings as required. |
3 | Laricina Energy (Laricina) voluntarily entered into the CCAA and obtained an order from the Court of Queen's Bench of Alberta, Judicial Centre of Calgary for creditor protection and stay of proceedings effective March 26, 2015. A final court order was granted on January 28, 2016, allowing the company to exit from protection under the CCAA and concluding the stay of proceedings against Laricina and its subsidiaries. |
4 | Ms. Salomone was a director of Crucible Materials Corp. (Crucible) from May 2008 to May 1, 2009. On May 6, 2009, Crucible and one of its affiliates filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware (the Bankruptcy Court). On August 26, 2010, the Bankruptcy Court entered an order confirming Crucible’s Second Amended Chapter 11 Plan of Liquidation. |
Director | Audit committee | Governance committee | Health, Safety & Environment committee | Human Resources committee |
Kevin E. Benson | ü | ü | ||
Derek H. Burney | ü | Chair | ||
Paule Gauthier | ü | ü | ||
S. Barry Jackson (Chair) | ü | ü | ||
John E. Lowe | ü | ü | ||
Paula Rosput Reynolds | ü | Chair | ||
John Richels | ü | ü | ||
Mary Pat Salomone | ü | ü | ||
D. Michael G. Stewart | ü | Chair | ||
Siim A. Vanaselja | Chair | ü | ||
Richard E. Waugh | ü | ü |
TCPL Annual information form 2015 | 33 |
Name | Present position held | Principal occupation during the five preceding years |
Russell K. Girling | President and Chief Executive Officer | President and Chief Executive Officer. |
Kristine L. Delkus | Executive Vice-President, Stakeholder Relations and General Counsel | Prior to October 2015, Executive Vice-President, General Counsel and Chief Compliance Officer. Prior to March 2014, Senior Vice-President, Pipelines Law and Regulatory Affairs. Prior to June 2012, Deputy General Counsel, Pipelines and Regulatory Affairs since September 2006 (TCPL). |
Wendy L. Hanrahan | Executive Vice-President, Corporate Services | Prior to May 2011, Vice-President, Human Resources since January 2005. |
Karl R. Johannson | Executive Vice-President and President, Natural Gas Pipelines | Prior to November 2012, Senior Vice-President, Canadian and Eastern U.S. Pipelines since January 2011. |
Donald R. Marchand | Executive Vice-President, Corporate Development and Chief Financial Officer | Prior to October 2015, Executive Vice-President and Chief Financial Officer since July 2010. |
Paul E. Miller | Executive Vice-President and President, Liquids Pipelines | Prior to March 2014, Senior Vice-President, Oil Pipelines. |
Alexander J. Pourbaix | Chief Operating Officer | Prior to October 2015, Executive Vice-President and President, Development. Prior to March 2014, President, Energy and Oil Pipelines since July 2010. |
William C. Taylor | Executive Vice-President and President, Energy | Prior to March 2014, Senior Vice-President, U.S. and Canadian Power. Prior to May 2013, Senior Vice-President, Eastern Power. |
Name | Present position held | Principal occupation during the five preceding years |
Sean M. Brett | Vice-President, Risk Management | Prior to August 2015, Vice-President and Treasurer since July 2010. |
Ronald L. Cook | Vice-President, Taxation | Vice-President, Taxation (TCC) since May 2003 and Vice-President, Taxation (TCPL) since April 2002. |
Joel E. Hunter | Vice-President, Finance and Treasurer | Prior to August 2015, Vice-President, Finance since July 2010. |
Christine R. Johnston | Vice-President, Law and Corporate Secretary | Prior to June 2014, Vice-President and Corporate Secretary. Prior to March 2012, Vice-President, Finance Law since January 2010. |
G. Glenn Menuz | Vice-President and Controller | Vice-President and Controller since June 2006. |
34 | TCPL Annual information form 2015 |
TCPL Annual information form 2015 | 35 |
($ millions) | 2015 | 2014 | ||
Audit fees | $7.8 | $6.4 | ||
• audit of the annual consolidated financial statements | ||||
• services related to statutory and regulatory filings or engagements | ||||
• review of interim consolidated financial statements and information contained in various prospectuses and other securities offering documents | ||||
Audit-related fees | $0.2 | $0.2 | ||
• services related to the audit of the financial statements of certain TransCanada post-retirement and post-employment plans | ||||
Tax fees | $0.5 | $0.5 | ||
• Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings | ||||
All other fees | — | — | ||
Total fees | $8.5 | $7.1 |
• | former executives or directors of TCPL or any of our subsidiaries |
• | this year’s nominated directors, and |
• | any associate of a director, executive officer or nominated director. |
36 | TCPL Annual information form 2015 |
Director | TransCanada common shares | TransCanada deferred share units | |||
K. Benson | 13,000 | 61,866 | |||
D. Burney | 12,318 | 56,230 | |||
P. Gauthier | 2,032 | 63,924 | |||
R. Girling1, 2 | 148,636 | — | |||
S.B. Jackson | 39,000 | 132,848 | |||
John E. Lowe | 15,000 | 2,271 | |||
P. Rosput Reynolds | 6,000 | 16,651 | |||
J. Richels3 | 10,000 | 13,866 | |||
M.P. Salomone | 2,000 | 8,512 | |||
D.M.G. Stewart4 | 16,008 | 27,882 | |||
S.A. Vanaselja | 12,000 | 7,898 | |||
R.E. Waugh5 | 29,730 | 18,557 |
1 | Mr. Girling is an employee of TCPL and participates in the Company's executive share unit program. He does not participate in the DSU program. Securities owned, controlled or directed include common shares that Mr. Girling has a right to acquire through exercise of stock options that are vested under the stock option plan, which is described in Schedule D to this AIF under the heading Compensation - Executive compensation. Directors as such do not participate in the stock option plan. Mr. Girling, as an employee of TCPL, has the right to acquire 1,798,026 TransCanada common shares under vested stock options, which amount is included in this chart. |
2 | Mr. Girling’s holdings include 4,000 shares held by his wife. |
3 | Mr. Richels’ holdings represent 10,000 shares held in a family partnership controlled by Mr. Richels and his wife. |
4 | Mr. Stewart's holdings include 2,052 shares held by his wife. |
5 | Mr. Waugh's holdings include 4,220 shares held by his wife. |
TCPL Annual information form 2015 | 37 |
1. | Additional information in relation to TCPL may be found under TCPL's profile on SEDAR (www.sedar.com). |
2. | Additional financial information is provided in TCPL's audited consolidated financial statements and MD&A for its most recently completed financial year. |
38 | TCPL Annual information form 2015 |
Units of measure | ||
Bbl/d | Barrel(s) per day | |
Bcf | Billion cubic feet | |
Bcf/d | Billion cubic feet per day | |
km | Kilometre | |
MMcf/d | Million cubic feet per day | |
MW | Megawatt(s) | |
MWh | Megawatt hours |
General terms and terms related to our operations | ||
bitumen | A thick, heavy oil that must be diluted to flow (also see: diluent). One of the components of the oil sands, along with sand, water and clay | |
cogeneration facilities | Facilities that produce both electricity and useful heat at the same time | |
diluent | A thinning agent made up of organic compounds. Used to dilute bitumen so it can be transported through pipelines | |
Eastern Triangle | Canadian Mainline region between North Bay, Toronto and Montréal | |
FIT | Feed-in tariff | |
force majeure | Unforeseeable circumstances that prevent a party to a contract from fulfilling it | |
GHG | Greenhouse gas | |
HSE | Health, safety and environment | |
investment base | Includes rate base as well as assets under construction | |
LNG | Liquefied natural gas | |
NEB 2014 Decision | In response to the RH-01 2014 Decision on the Canadian Mainline's 2015-2030 Tolls Application | |
OM&A | Operating, maintenance and administration | |
PJM Interconnection area (PJM) | A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia | |
PPA | Power purchase arrangement | |
rate base | Our annual average investment used | |
WCSB | Western Canada Sedimentary Basin |
Accounting terms | ||
DRP | Dividend reinvestment plan | |
GAAP | U.S. generally accepted accounting principles | |
ROE | Rate of return on common equity |
Government and regulatory bodies terms | ||
CFE | Comisión Federal de Electricidad (Mexico) | |
DOS | Department of State (U.S.) | |
FERC | Federal Energy Regulatory Commission (U.S.) | |
IESO | Independent Electricity System Operator | |
NAFTA | North American Free Trade Agreement | |
NEB | National Energy Board (Canada) | |
SEC | U.S. Securities and Exchange Commission | |
SGER | Specified Gas Emitters Regulations |
TCPL Annual information form 2015 | 39 |
Metric | Imperial | Factor |
Kilometres (km) | Miles | 0.62 |
Millimetres | Inches | 0.04 |
Gigajoules | Million British thermal units | 0.95 |
Cubic metres* | Cubic feet | 35.3 |
Kilopascals | Pounds per square inch | 0.15 |
Degrees Celsius | Degrees Fahrenheit | to convert to Fahrenheit multiply by 1.8, then add 32 degrees; to convert to Celsius subtract 32 degrees, then divide by 1.8 |
* | The conversion is based on natural gas at a base pressure of 101.325 kilopascals and at a base temperature of 15 degrees Celsius. |
40 | TCPL Annual information form 2015 |
We believe that strong governance improves corporate performance and benefits all stakeholders. This section discusses our approach to governance and describes our Board and how it works. | ||||||
WHERE TO FIND IT | ||||||
> | About our governance practices | |||||
Board characteristics | ||||||
Governance philosophy | ||||||
About our governance practices Our Board and management are committed to the highest standards of ethical conduct and corporate governance. TransCanada is a public company listed on the TSX and the NYSE, and we recognize and respect rules and regulations in both Canada and the U.S. Our corporate governance practices comply with the Canadian governance guidelines, which include the governance rules of the TSX and Canadian Securities Administrators (CSA): | Role and responsibilities of the Board | |||||
Orientation and education | ||||||
Board effectiveness and director assessment | ||||||
Engagement | ||||||
Communicating with the Board | ||||||
Shareholder proposals | ||||||
Board committees | ||||||
• | National Instrument 52-110, Audit Committees, |
• | National Policy 58-201, Corporate Governance Guidelines, and |
• | National Instrument 58-101, Disclosure of Corporate Governance Practice (NI 58-101). |
TCPL Annual information form 2015 | 41 |
TCPL Annual information form 2015 | 42 |
• | directors may not serve on more than six boards in total, and |
• | Audit committee members may not serve on more than three audit committees in total. |
TCPL Annual information form 2015 | 43 |
TCPL Annual information form 2015 | 44 |
TCPL Annual information form 2015 | 45 |
TCPL Annual information form 2015 | 46 |
TCPL Annual information form 2015 | 47 |
TCPL Annual information form 2015 | 48 |
Committee | Risk focus | Description |
Audit | Financial risk | • Oversees management’s role in monitoring compliance with financial risk management policies and procedures and reviewing the adequacy of our financial risk management. • Ensures that: • our financial risk management strategies, policies and limits are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance, and • risks are managed within limits that are ultimately established by the Board, implemented by senior management and monitored by our risk management and internal audit groups. • Oversees cybersecurity and its related risks to TransCanada. |
Governance | Risk management process and management allocation of risks | • Reviews TransCanada’s ‘top-of-mind’ business risks with management at each committee meeting. • Oversees the risk responsibility matrix with management annually to ensure there is proper Board and committee oversight according to the terms of their charters. • Ensures that we have management programs in place to mitigate those risks. • Recommends, along with the respective committee (or executive) assigned responsibility for specific risks, any enhancements to our risk management program and policies to the Board. |
Health, Safety and Environment | Operational risk, people and process safety, security and environmental risk | • Monitors compliance with our health, safety and environment (HSE) corporate policy through regular reporting from management, within the framework of our integrated HSE management system that is used to capture, organize and document our related policies, programs and procedures. See the next page for more details. |
Human Resources | Human resources and compensation risk | • Oversees the compensation policies and practices to effectively identify and mitigate compensation risks and discourage members of the executive leadership team or others from taking inappropriate or excessive risks and to ensure our compensation policies are not reasonably likely to have a material adverse effect on TransCanada. • See Compensation governance starting on page 56 for more information about how we manage our compensation risk. |
TCPL Annual information form 2015 | 49 |
• | Planning: risk and regulatory assessment, objectives and targets, and structure and responsibility |
• | Implementing: development and implementation of programs, plans, procedures and practices aimed at operational risk management |
• | Reporting: document and records management, communication and reporting, and |
• | Action: ongoing audit and review of HSE performance. |
TCPL Annual information form 2015 | 50 |
TCPL Annual information form 2015 | 51 |
TCPL Annual information form 2015 | 52 |
TCPL Annual information form 2015 | 53 |
Date | Topic | Presented/hosted by | Attended by |
March 17 | Cybersecurity risk environment | National Association of Corporate Directors | Mary Pat Salomone |
April 1 | Corporate governance | Les Affaires Newspaper and Institute of Corporate Directors | Paule Gauthier |
April 30 | Strategic issues session – corporate development projects and Bruce Power Board leadership conference | Members of the executive leadership team | All directors |
June 15 | Operational risk education session | Members of the executive leadership team | All directors |
June 15 | Strategic planning session – economic outlook and shareholder value | Members of the executive leadership team | All directors |
September 9 | Strategic issues session – Bruce Power | Executive Vice-President and President, Energy | All directors |
October 1 | Site visit - emergency response plan field exercise, Riverside Park, Yankton, South Dakota | Vice-President, Pipeline Safety & Compliance | D. Michael G. Stewart |
November 2 | Strategic issues session – federal election outcome; current M&A and capital market trends | Governance committee chair and Vice-President, Government Relations; Senior Vice-President, Strategy and Corporate Development | All directors |
December 3 | Director orientation session | Members of the executive leadership team | John Lowe |
December 3 | Strategic issues session – Liquids Pipelines strategy and current M&A and capital market trends | Executive Vice-President and President, Liquids Pipelines and Senior Vice-President, Strategy and Corporate Development | All directors |
December 3 | Tour of Calgary Oil Operations Control Centre and received presentation on outcome of emergency response exercise held in Riverside Park, Yankton South Dakota | VP, Pipeline Safety & Compliance | HSE Committee members and Kevin Benson |
December 15 | Tour of FPL Solar Energy Plant, Palm Beach, Florida | WomenCorporateDirectors (WCD) | Mary Pat Salomone |
TCPL Annual information form 2015 | 54 |
TCPL Annual information form 2015 | 55 |
The committee ensures that the Board seeks expertise in the following key areas: | |
• Accounting & finance • Energy/utilities • Engineering • Governance • Government/regulatory • Health, safety and environment | • International markets • Law • Management/leadership • Oil & gas/utilities • Operations, and • Risk management. |
TCPL Annual information form 2015 | 56 |
Matrix of expected retirement year, education, committees (Audit, Governance, Human Resources, Health Safety and Environment) and key expertise areas (accounting/finance, energy/utilities, engineering, ect.) for Kevin Benson, Derek Burney, Russ Girling, Barry Jackson, John Lowe, Paula Reynolds, John Richels, Mary Pat Salomone, Indira Samarasekera, Michael Stewart, Siim Vanaselja, Richard Waugh |
TCPL Annual information form 2015 | 57 |
TCPL Annual information form 2015 | 58 |
TCPL Annual information form 2015 | 59 |
• | notify the Corporate Secretary in writing, and |
• | provide the information required in our By-law Number 1, which can be found on our website (www.transcanada.com) or on SEDAR (www.sedar.com). |
Type of meeting | Announcement timing | Advance notice deadline |
Annual meeting | Public announcement more than 50 days before meeting | Not less than 30 days before meeting |
Public announcement 50 days or less before meeting | Not less than 10 days following the first public announcement of the meeting | |
Special meeting to elect directors | Public announcement more than 50 days before meeting | Not less than 15 days before meeting |
Public announcement 50 days or less before meeting | Not less than 15 days following the first public announcement of the meeting |
TCPL Annual information form 2015 | 60 |
TCPL Annual information form 2015 | 61 |
Members | Siim Vanaselja (Chair) Kevin E. Benson Derek H. Burney John Lowe (as of September 9, 2015) Mary Pat Salomone D. Michael G. Stewart |
Meetings in 2015 | 5 regularly scheduled meetings (February, April, July, November, December) |
Independent | 6 independent directors, 100 per cent independent and financially literate. |
Mr. Vanaselja, Mr. Benson and Mr. Lowe are “audit committee financial experts” as defined by the SEC in the U.S., and each have the accounting or related financial management experience required under the NYSE rules. | |
Mandate | The Audit committee is responsible for assisting the Board in overseeing the integrity of our financial statements and our compliance with legal and regulatory requirements. |
It is also responsible for overseeing and monitoring the internal accounting and reporting process and the process, performance and independence of our internal and external auditors. | |
• | Reviewed our 2015 interim and annual disclosure documents including the unaudited interim and audited annual consolidated financial statements and related management’s discussion and analysis, AIF and circular and recommended them for approval. |
• | Oversaw our financial reporting risks including issues relating to materiality and risk assessment. |
• | Received the external auditor’s formal written statement of independence (which sets out all of its relationships with TransCanada) and its comments to management about our internal controls and procedures. |
• | Reviewed the appointment of the external auditors and estimated fees and recommended them to the Board for approval. |
• | Reviewed the audit plans of the internal and external auditors and pre-approved the non-audit services performed by KPMG relating to tax and benefit plans. |
• | Recommended the funding of the Registered Pension Plan and Supplemental Pension Plan. |
• | Reviewed the major accounting policies and estimates. |
• | Oversaw a request for proposal process for our external auditor. |
• | Received reports from management on our cybersecurite plans and initiatives. |
• | Monitored Canadian and U.S. financial reporting and legal and regulatory developments affecting our financial reporting process, controls and disclosure. |
• | Reviewed and recommended changes to the suite of risk management policies, and reviewed developments and reports relating to counterparty, insurance and market risks. |
• | Reviewed and recommended prospectuses relating to issuance of securities. |
• | Recommended amendments to the Public disclosure policy and Code of business ethics. |
• | Approved annual election to enter into uncleared swaps as permitted under U.S. legislation and monitored compliance. |
• | Received regular reports from management on risk management, finance and liquidity, treasury, pensions, compliance, material litigation and information services security controls. |
• | Reviewed regular reports from Internal Audit. |
• | Reviewed adequacy of staff complements in accounting and tax. |
• | Recommended amendments to the Audit committee charter. |
TCPL Annual information form 2015 | 62 |
Members | Derek H. Burney (Chair) Kevin E. Benson S. Barry Jackson Siim A. Vanaselja Richard E. Waugh |
Meetings in 2015 | 3 regularly scheduled meetings (February, April, November) |
Independent | 5 independent directors, 100 per cent independent |
Mandate | The Governance committee is responsible for assisting the Board with maintaining strong governance policies and practices at TransCanada, reviewing the independence and financial literacy of directors, managing director compensation and the Board assessment process, and overseeing our strategic planning process and risk management activities. |
It monitors the relationship between management and the Board, directors’ share ownership levels, governance developments and emerging best practices. It is also responsible for identifying qualified candidates for the Board to consider as potential directors. | |
It also recommends the meeting schedule for Board and committee meetings, site visits, and oversees matters related to the timing of our annual meeting. | |
• | Reviewed the independence of each director according to our written criteria to give the Board guidance in its annual assessment of independence and the structure and composition of each committee and the other directorships held by Board members (including public and private companies, Crown corporations and non-profit organizations). |
• | Oversaw our strategic planning process, including strategic issues to be considered and planning of our strategic issues and planning sessions. |
• | Oversaw our risk management activities, including receiving updates on key business risks and making recommendations to the Board as appropriate. |
• | Reviewed the identified principal risks with management to ensure we have proper Board and committee oversight and management programs in place to mitigate risks. |
• | Monitored director share ownership requirements. |
• | Reviewed our Corporate governance guidelines and committee charters and recommended appropriate changes to the Board for approval. The changes included |
• | limiting the total number of audit committees that an Audit committee member may serve on to three, and |
• | beginning in 2016, the Governance committee charter includes oversight of lobbying policies, activities and expenditures. |
• | Reviewed say on pay updates and voting trends. |
• | Oversaw the annual assessment of the Board, committees and Chair. |
• | Monitored updates to securities regulations (regulation and legal updates affecting our policies, procedures and disclosure practices) and matters relating to the financial markets. The committee continues to monitor legal developments and emerging best practices in Canada, the U.S. and internationally. |
• | Oversaw the Board’s retirement policy, Board renewal and the selection of new director candidates. |
TCPL Annual information form 2015 | 63 |
Members | D. Michael G. Stewart (Chair) Paule Gauthier (retiring April 29, 2016) John Lowe (as of September 9, 2015) Paula Rosput Reynolds John Richels Mary Pat Salomone |
Meetings in 2015 | 3 regularly scheduled meetings (February, May and November) |
Independent | 6 independent directors, 100 per cent independent |
Mandate | The Health, Safety and Environment committee is responsible for oversight for health, safety, security and environmental matters (HSE matters). |
The committee reviews and monitors: | |
• the performance and activities of TransCanada on HSE matters including compliance with applicable and proposed legislation, regulations and orders; conformance with industry standards and best practices; people, health, safety and security; process safety, asset reliability; operational risk management and asset integrity plans and programs; and emergency response plans and programs; • the systems, programs and policies relating to HSE matters and whether they are being appropriately developed and effectively implemented; • actions and initiatives undertaken by TransCanada to prevent, mitigate and manage risks related to HSE matters which may have the potential to adversely impact the our operations, activities, plans, strategies or reputation; or prevent loss or injury to our employees and assets or operations from malicious acts, natural disasters or other crisis situations; • any critical incidents respecting our assets or operations involving: the fatality of or a life threatening injury to a person; any pipeline ruptures resulting in significant property damage or loss of product; any whistleblower events relating to HSE matters; or any incidents involving personnel and public safety, property damage, environmental damage or physical security that have the potential to severely and adversely impact our reputation and or business continuity; and • significant regulatory audits, findings, orders, reports and/or recommendations issued by or to TransCanada related to HSE matters or issues, together with management's response thereto. | |
• | Received and reviewed regular reports on HSE related activities, performance and compliance. |
• | Received regular reports on operational risk management, people and process safety and regulatory compliance matters related to asset integrity. |
• | Reviewed the status of critical incidents, root cause analysis and incident follow-up. |
• | Monitored management’s response and the status of corrective action plans to significant audits from the National Energy Board, Pipeline and Hazardous Materials Safety Administration and other regulatory agencies. |
• | Oversaw our risk management activities related to health, safety, security and environment, and reported to the Board as appropriate. |
• | Monitored the effectiveness of health, safety and environment policies, management systems, programs, procedures and practices through the receipt of reports on four levels of governance activities related to internal and external audit findings. |
• | Monitored updates to Canadian and U.S. air emissions and greenhouse gas legislation, climate change initiatives and related compliance matters. |
• | Visited the Calgary Oil Operations Control Centre. |
• | The Chair observed a Keystone pipeline emergency response field exercise along the Missouri River at Yankton, South Dakota. |
• | Attended a special session on operational risk management which involved the use of an external speaker. |
• | Revised the charter to clarify and better articulate the role and responsibilities of the committee. |
• | Received and reviewed regular reports on the operational and HSE performance at Bruce Power. |
TCPL Annual information form 2015 | 64 |
Members | Paula Rosput Reynolds (Chair) Paule Gauthier (retiring April 29, 2016) S. Barry Jackson John Richels Richard E. Waugh |
Meetings in 2015 | 5 regularly scheduled meetings (January, February, July, November and December) |
Independent | 5 independent directors, 100 per cent independent |
Mandate | The Human Resources committee is responsible for assisting the Board with developing strong human resources policies and plans, overseeing the compensation programs, and assessing the performance of the CEO and other members of the executive leadership team against pre-established objectives and recommending their compensation to the Board. |
It approves all executive incentive awards, and any major changes to the compensation programs and benefits plans for employees. It is also responsible for the benefits under our Canadian pension plans and reviewing our share ownership requirements for executives. | |
• | Assessed the performance of the executive leadership team and recommended the 2015 executive compensation awards to the Board for approval. |
• | Reappointed Meridian Compensation Partners as the independent compensation advisor to the committee. |
• | Developed and approved a new peer group for benchmarking executive compensation. |
• | Reviewed and recommended to the Board an Incentive compensation reimbursement ('clawback') policy which took effect in February 2015. |
• | Approved an increase in the share ownership requirement for the CEO from four to five times base salary and determined that all executives must meet their requirements through direct share ownership. |
• | Reviewed and recommended to the Board amendments to our executive separation agreements to align with current governance standards. |
• | Simplified the approach to determining long-term incentive awards for the named executives by eliminating the ranges and setting specific target award levels for each named executive based on median market data as well as individual performance and potential to contribute to TransCanada's future success. |
• | Reviewed the executive share unit plan and approved: |
• | the introduction of an additional performance measure in the plan (earnings per share) and modified the performance peer group used for the relative total shareholder return (TSR) measure, |
• | the elimination of the minimum payout of 50%, and |
• | the increase of the maximum payout to 200%. |
• | Reviewed our talent strategy and succession planning programs. |
TCPL Annual information form 2015 | 65 |
• | Company’s financial accounting and reporting process; |
• | integrity of the financial statements; |
• | Company’s internal control over financial reporting; |
• | external financial audit process; |
• | compliance by the Company with legal and regulatory requirements; and |
• | independence and performance of the Company’s internal and external auditors. |
a) | review, discuss with management and the external auditor and recommend to the Board for approval, the Company’s audited annual consolidated financial statements, annual information form, management’s discussion and analysis, all financial information in prospectuses and other offering memoranda, financial statements required by regulatory authorities, all prospectuses and all documents which may be incorporated by reference into a prospectus, including, without limitation, the annual management information circular, but excluding any pricing or prospectus supplement relating to the issuance of debt securities of the Company; |
b) | review, discuss with management and the external auditor and recommend to the Board for approval, the release to the public of the Company’s interim reports, including the consolidated financial statements, management’s discussion and analysis and press releases on quarterly financial results; |
c) | review and discuss with management and the external auditor the use of non-GAAP information and the applicable reconciliation; |
d) | review and discuss with management any financial outlook or future-oriented financial information disclosure in advance of its public release; provided, however, that such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made). The Audit Committee need not discuss in advance each instance in which the Company may provide financial projections or presentations to credit rating agencies; |
e) | review with management and the external auditor major issues regarding accounting and auditing policies and practices, including any significant changes in the Company’s selection or application of accounting policies, as well as major issues as to the adequacy of the Company’s internal controls and any special audit steps adopted in light of material control deficiencies that could significantly affect the Company’s financial statements; |
f) | review and discuss quarterly findings reports from the external auditor on: |
66 | TCPL Annual information form 2015 |
(i) | all critical accounting policies and practices to be used; |
(ii) | all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; |
(iii) | other material written communications between the external auditor and management, such as any management letter or schedule of unadjusted differences; |
g) | review with management and the external auditor the effect of regulatory and accounting developments as well as any off-balance sheet structures on the Company’s financial statements; |
h) | review with management, the external auditor and, if necessary, legal counsel, any litigation, claim or contingency, including arbitration and tax assessments, that could have a material effect upon the financial position of the Company, and the manner in which these matters have been disclosed in the financial statements; |
i) | review disclosures made to the Audit Committee by the Company’s CEO and CFO during their certification process for the periodic reports filed with securities regulators about any significant deficiencies in the design or operation of internal controls or material weaknesses therein and any fraud involving management or other employees who have a significant role in the Company’s internal controls; |
j) | discuss with management the Company’s material financial risk exposures and the steps management has taken to monitor and control such exposures, including the Company’s risk assessment and risk management policies; |
(a) | review with the Company’s General Counsel legal matters that may have a material impact on the financial statements, the Company’s compliance policies and any material reports or inquiries received from regulators or governmental agencies; |
(a) | review and approve the audit plans of the internal auditor of the Company including the degree of coordination between such plans and that of the external auditor and the extent to which the planned audit scope can be relied upon to detect weaknesses in internal control, fraud or other illegal acts; |
(b) | review the significant findings prepared by the internal audit department and recommendations issued by it or by any external party relating to internal audit issues, together with management’s response thereto; |
(c) | review compliance with the Company’s policies and avoidance of conflicts of interest; |
(d) | review the report prepared by the internal auditor on officers' expenses and aircraft usuage; |
(e) | review the adequacy of the resources of the internal auditor to ensure the objectivity and independence of the internal audit function, including reports from the internal audit department on its audit process with subsidiaries and affiliates; |
(f) | ensure the internal auditor has access to the Chair of the Audit Committee, the Board and the Chief Executive Officer and meet separately with the internal auditor to review with him or her any problems or difficulties he or she may have encountered and specifically: |
(i) | any difficulties which were encountered in the course of the audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management; |
(ii) | any changes required in the planned scope of the internal audit; |
(iii) | the internal audit department responsibilities, budget and staffing; and to report to the Board on such meetings; |
(a) | review any letter, report or other communication from the external auditor in respect of any identified weakness or unadjusted difference and management’s response and follow-up, inquire regularly of management and the external auditor of any significant issues between them and how they have been resolved, and intervene in the resolution if required; |
(b) | receive and review annually the external auditor’s formal written statement of independence delineating all relationships between itself and the Company; |
TCPL Annual information form 2015 | 67 |
(c) | meet separately with the external auditor to review any problems or difficulties the external auditor may have encountered and specifically: |
(i) | any difficulties which were encountered in the course of the audit work, including any restrictions on the scope of activities or access to required information, and any disagreements with management; |
(ii) | any changes required in the planned scope of the audit; and to report to the Board on such meetings; |
(d) | meet with the external auditor prior to the audit to review the planning and staffing of the audit; |
(e) | receive and review annually the external auditor's written report on their own internal quality control procedures; any material issues raised by the most recent internal quality control review, or peer review, of the external auditor, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, and any steps taken to deal with such issues; |
(f) | review and evaluate the external auditor, including the lead partner of the external auditor team; |
(g) | ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law, but at least every five years; |
(a) | pre-approve all audit services (which may entail providing comfort letters in connection with securities underwritings) and all permitted non-audit services, other than non-audit services where: |
(i) | the aggregate amount of all such non-audit services provided to the Company that were not pre-approved constitutes not more than 5 per cent of the total fees paid by the Company and its subsidiaries to the external auditor during the fiscal year in which the non-audit services are provided; |
(ii) | such services were not recognized by the Company at the time of the engagement to be non-audit services; |
(iii) | such services are promptly brought to the attention of the Audit Committee and approved prior to the completion of the audit by the Audit Committee or by one or more members of the Audit Committee to whom authority to grant such approvals has been delegated by the Audit Committee; |
(b) | approval by the Audit Committee of a non-audit service to be performed by the external auditor shall be disclosed as required under securities laws and regulations; |
(c) | the Audit Committee may delegate to one or more designated members of the Audit Committee the authority to grant pre-approvals required by this subsection. The decisions of any member to whom authority is delegated to pre-approve an activity shall be presented to the Audit Committee at its first scheduled meeting following such pre-approval; |
(d) | if the Audit Committee approves an audit service within the scope of the engagement of the external auditor, such audit service shall be deemed to have been pre-approved for purposes of this subsection; |
(a) | review and recommend to the Board for approval the implementation of, and significant amendments to, policies and program initiatives deemed advisable by management or the Audit Committee with respect to the Company’s code of business ethics (COBE) risk management and financial reporting policies; |
(b) | obtain reports from management, the Company’s senior internal auditing executive and the external auditors and report to the Board on the status and adequacy of the Company’s efforts to ensure its businesses are conducted and its facilities are operated in an ethical, legally compliant and socially responsible manner, in accordance with the Company’s codes of business conduct and COBE; |
(c) | establish a non-traceable, confidential and anonymous system by which callers may ask for advice or report any ethical or financial concern, ensure that procedures for the receipt, retention and treatment of complaints in respect of accounting, internal controls and auditing matters are in place, and receive reports on such matters as necessary; |
(d) | annually review and assess the adequacy of the Company’s public disclosure policy; |
68 | TCPL Annual information form 2015 |
(e) | review and approve the Company’s hiring policies for partners, employees and former partners and employees of the present and former external auditor (recognizing the Sarbanes-Oxley Act of 2002 does not permit the CEO, controller, CFO or chief accounting officer to have participated in the Company’s audit as an employee of the external auditor during the preceding one-year period) and monitor the Company’s adherence to the policy; |
(a) | review and approve annually the Statement of Investment Beliefs for the Company’s pension plans; |
(b) | delegate the ongoing administration and management of the financial aspects of the Canadian pension plans to the Pension Committee comprised of members of the Company’s management team appointed by the Human Resources Committee, in accordance with the Pension Committee Charter, which terms shall be approved by both the Audit Committee and the Human Resources Committee, and the terms of the Statement of Investment Beliefs; |
(c) | monitor the financial management activities of the Pension Committee and receive updates at least annually from the Pension Committee on the investment of the Plan assets to ensure compliance with the Statement of Investment Beliefs; |
(d) | provide advice to the Human Resources Committee on any proposed changes in the Company’s pension plans in respect of any significant effect such changes may have on pension financial matters; |
(e) | review and consider financial and investment reports and the funded status relating to the Company’s pension plans and recommend to the Board on pension contributions; |
(f) | receive, review and report to the Board on the actuarial valuation and funding requirements for the Company’s pension plans; |
(g) | approve the initial selection or change of actuary for the Company’s pension plans; |
(h) | approve the appointment or termination of auditor; |
(a) | review and approve the engagement and related fees of the auditor for any plan of a U.S. subsidiary that offers Company stock to employees as an investment option under the plan; |
(a) | review annually the reports of the Company’s representatives on certain audit committees of subsidiaries and affiliates of the Company and any significant issues and auditor recommendations concerning such subsidiaries and affiliates; |
(b) | oversee succession planning for the senior management in finance, treasury, tax, risk, internal audit and the controllers’ group; and |
(a) | review, at least quarterly, the report of the Chief Information Officer (or such other appropriate Company representative) on information security controls, education and awareness. |
TCPL Annual information form 2015 | 69 |
(a) | review and approve the agenda for each meeting of the Audit Committee and, as appropriate, consult with members of management; |
(b) | preside over meetings of the Audit Committee; |
(c) | make suggestions and provide feedback from the Audit Committee to management regarding information that is or should be provided to the Audit Committee; |
(d) | report to the Board on the activities of the Audit Committee relative to its recommendations, resolutions, actions and concerns; and |
(e) | meet as necessary with the internal and external auditor. |
70 | TCPL Annual information form 2015 |
TCPL Annual information form 2015 | 71 |
We are committed to high standards of corporate governance, including compensation governance. This section tells you how the Board makes director and executive compensation decisions at TransCanada, and explains its decisions for 2015. | |||||||
WHERE TO FIND IT | |||||||
> | Compensation governance | ||||||
Expertise | |||||||
Compensation oversight | |||||||
Compensation governance The Board, the Human Resources committee and the Governance committee are responsible for the integrity of our compensation governance practices. | Independent consultant | ||||||
> | Director compensation | ||||||
Director compensation discussion and analysis | |||||||
2015 details | |||||||
Human Resources committee • Paula Rosput Reynolds (Chair) • Paule Gauthier (retiring April 29, 2016) • S. Barry Jackson • John Richels • Richard E. Waugh | Governance committee • Derek H. Burney (Chair) • Kevin E. Benson • S. Barry Jackson • Siim A. Vanaselja • Richard E. Waugh | > | Executive compensation | ||||
Human Resources committee letter to shareholders | |||||||
Executive compensation discussion and analysis | |||||||
2015 details | |||||||
The Board approves all matters related to executive and director compensation. The committees are responsible for reviewing compensation matters and making any recommendations. Both committees are entirely independent. Each Human Resources committee member is independent under the NYSE compensation committee independence requirements. |
TCPL Annual information form 2015 | 72 |
Name | Human resources/ compensation experience | CEO/EVP experience | Risk management | Governance | Law | Finance & accounting |
Paula Rosput Reynolds (Chair) | X | X | X | X | X | |
Paule Gauthier (retiring April 29, 2016) | X | X | X | |||
S. Barry Jackson | X | X | X | X | ||
John Richels | X | X | X | X | X | X |
Richard E. Waugh | X | X | X | X | X |
TCPL Annual information form 2015 | 73 |
TCPL Annual information form 2015 | 74 |
• | Structured process: The committee has implemented a formal decision-making process that involves management, the committee and the Board. The committee uses a multi-step review process for all compensation matters, first adopting goals and metrics of performance, reviewing how performance compares to the pre-established metrics and then seeking Board input as to the reasonableness of the results. |
• | Benchmarking to ensure fairness: Executive compensation is reviewed every year. Director compensation is reviewed every two years by the Governance committee and the Board. Both director and executive compensation are benchmarked against size appropriate peer groups to assess competitiveness and fairness, and the appropriateness of the composition of the applicable peer groups is reviewed. |
• | Modelling and stress testing: The committee uses modelling to stress test different compensation scenarios and potential future executive compensation. This includes an analysis of the potential effect of different corporate performance scenarios on previously awarded and outstanding compensation to assess whether the results are reasonable. The committee also uses modelling to assess the payments under the terms of the executives’ employment agreements for severance and change of control situations. |
• | Independent advice: The committee uses an independent external compensation consultant to provide advice in connection with executive pay benchmarking, incentive plan design, compensation governance and pay for performance. |
• | Alignment with shareholders: The committee and the Board place a significant emphasis on long-term incentives when determining the total direct compensation for the executive leadership team. Our long-term incentives include stock options and performance vesting executive share units (ESUs) – both of which encourage value creation over the long-term and align executives’ interests with our shareholders. |
• | Pre-established objectives: Each year the Board approves corporate, business/functional and individual objectives that are aligned with the overall business plan for each member of the executive leadership team. These objectives are used to assess performance and determine compensation. |
• | Multi-year performance-based compensation: Awards under the ESU plan are paid out based on our performance against objectives set for the three-year vesting period. |
• | Limits on variable compensation payments: Short-term incentive awards are subject to a maximum payout of two times target. Long-term incentive awards under the ESU plan are limited to a maximum payout of 1.5 times the final number of units accrued at the end of the vesting period (2.0 times starting with the 2015 grant). |
• | Discretion: The Board completes a formal assessment annually, and can then use its discretion to increase or decrease any compensation awards if it deems it appropriate based on market factors or other extenuating circumstances. However, to maintain the integrity of the metrics-based framework, the Board exercises its discretion sparingly. |
TCPL Annual information form 2015 | 75 |
• | Corporate objectives: We adopt corporate objectives consistent with our approved financial plan so that the Board can monitor how compensation influences business decisions. |
• | Recommended amendments: We recommended amendments to the stock option plan, including an increase to the number of shares reserved for issuance to allow for option grants over the next three years, for shareholder approval. |
• | Share ownership requirements: We have share ownership requirements for both directors and executives, reflecting the Board’s view that directors and executives can represent the interests of shareholders more effectively if they have a significant investment in TransCanada. |
• | Prohibition on hedging: Our trading policy includes an Anti-hedging policy preventing directors and officers from using derivatives or other instruments to insulate them from movements in our share price. This includes prepaid variable forward contracts, equity swaps, collars and units of exchange funds. |
• | Reimbursement: If there is an incidence of misconduct with our financial reporting and we must restate our financial statements because of material non-compliance with a financial reporting requirement, our CEO and CFO are required by law to reimburse TransCanada for incentive-based compensation related to the period the misconduct occurred. They must also reimburse us for any profits they realized from trading TransCanada securities during the 12 months following the issue of the misstated financial statements. |
• | Say on pay: We implemented a non-binding advisory shareholder vote on our approach to executive compensation starting in 2010. The results shown in the table below confirm that a significant majority of shareholders have accepted our approach to executive compensation. The approval vote as a percentage of shares voted in favour of our approach to executive compensation for the last three years are as follows: |
Year | Approval vote (%) |
2015 | 97.34 |
2014 | 94.28 |
2013 | 92.67 |
• | Code of business ethics: Our Code of business ethics applies to employees, contract workers, independent consultants and directors. The Code incorporates principles of good conduct and ethical and responsible behaviour to guide our decisions and actions and the way we conduct business. |
TCPL Annual information form 2015 | 76 |
Meridian | 2015 | 2014 | |||||
Consulting to the Human Resources committee | 0.17 | 0.09 | |||||
Willis Towers Watson | |||||||
Consulting to the Human Resources committee | - | 0.04 | |||||
Consulting to human resources management | |||||||
• compensation consulting and market data services for executives and non-executives | 0.03 | 0.15 | |||||
• benefit and pension actuarial consulting services for our Canadian and U.S. operations | 2.77 | 2.53 | |||||
• pension administration services for our Canadian and U.S. operations | 1.85 | 2.01 | |||||
Consulting to the Governance committee | |||||||
• preparing a report on director compensation | - | 0.03 | |||||
All other fees | - | - | |||||
Total fees | $ | 4.82 | $ | 4.85 |
TCPL Annual information form 2015 | 77 |
Director compensation discussion and analysis APPROACH Our director compensation program reflects our size and complexity, and reinforces the importance we place on delivering shareholder value. Director compensation includes annual retainers and meeting fees that are paid in cash and DSUs to link a significant portion of their compensation to the value of our shares (see Deferred share units, below for more information about the DSU plan). The Board follows a formal performance assessment process to ensure directors are engaged and make meaningful contributions to the Board and committees they serve on. | ||||||
WHERE TO FIND IT | ||||||
> | Director compensation discussion and analysis | |||||
Approach | ||||||
Components | ||||||
> | 2015 details | |||||
Director compensation table | ||||||
At-risk investment | ||||||
Incentive plan awards | ||||||
TCPL Annual information form 2015 | 78 |
Custom peer group | General industry peer group |
ATCO Ltd. | Agrium Inc. |
Canadian Natural Resources Ltd. | Canadian National Railway Company |
Cenovus Energy Inc. | Canadian Pacific Railway Limited |
Enbridge Inc. | Cenovus Energy Inc. |
Encana Corporation | Enbridge Inc. |
Fortis Inc. | Encana Corporation |
Husky Energy Inc. | Maple Leaf Foods Inc. |
Imperial Oil Ltd. | Metro Inc. |
Suncor Energy Inc. | National Bank of Canada |
Talisman Energy Inc. | Potash Corporation of Saskatchewan Inc. |
TransAlta Corporation | Resolute Forest Products Inc. |
Suncor Energy Inc. | |
Talisman Energy Inc. | |
TELUS Corporation |
TCPL Annual information form 2015 | 79 |
TCPL Annual information form 2015 | 80 |
2015 compensation | |||
Retainers paid quarterly from the date the director is appointed to the Board and committees | |||
Board paid to each director except the Chair of the Board | $180,000 per year ($70,000 cash + $110,000 in DSUs) | represented 2,309 DSUs for Canadian directors and 3,034 DSUs for U.S. directors in 2015 | |
Chair of the Board receives a higher retainer because of his level of responsibility | $491,000 per year ($201,000 in cash + $290,000 in DSUs) | represented 6,110 DSUs in 2015 | |
Committee paid to each committee member except the Chair of the committee | $5,500 per year | ||
Committee Chairs receive a higher committee retainer for additional duties and responsibilities | $20,000 per year | Audit | |
$15,000 per year | Human resources | ||
$12,000 per year | Governance and health, safety and environment | ||
Meeting fees Board and committee meetings | $1,500 per meeting | ||
Travel fees if round trip travel is more than three hours | $1,500 per round trip | ||
Other fees special assignments | $1,500 (per diem for additional activities) | no other fees were paid in 2015 |
TCPL Annual information form 2015 | 81 |
Director compensation – 2015 details |
Name | Fees earned ($) | Share- based awards ($) | Option- based awards ($) | Non-equity incentive plan compensation ($) | Pension value ($) | All other compensation ($) | Total ($) | ||||
Kevin E. Benson | 114,320 | 110,000 | – | – | – | – | 224,320 | ||||
Derek H. Burney | 122,000 | 110,000 | – | – | – | – | 232,000 | ||||
Paule Gauthier (retiring April 29, 2016) | 118,500 | 110,000 | – | – | – | – | 228,500 | ||||
S. Barry Jackson | 201,000 | 290,000 | – | – | – | 44,030 | 535,030 | ||||
John Lowe (joined September 9, 2015) | 38,592 | 34,356 | 72,948 | ||||||||
Paula Rosput Reynolds | 128,000 | 110,000 | – | – | – | – | 238,000 | ||||
John Richels | 117,000 | 110,000 | – | – | – | – | 227,000 | ||||
Mary Pat Salomone | 117,000 | 110,000 | – | – | – | – | 227,000 | ||||
D. Michael G. Stewart | 117,500 | 110,000 | – | – | – | – | 227,500 | ||||
Siim A. Vanaselja | 125,180 | 110,000 | – | – | – | – | 235,180 | ||||
Richard E. Waugh | 117,000 | 110,000 | – | – | – | – | 227,000 |
• | Mr. Lowe, Ms. Reynolds, Mr. Richels and Ms. Salomone received their compensation in U.S. dollars. |
• | Fees earned includes Board and committee retainers, meeting fees and travel fees paid in cash, including the portion they chose to receive as DSUs. |
• | Share-based awards include the portion of the Board retainer ($110,000) and the Board Chair retainer ($290,000) that we automatically pay in DSUs. There were no additional grants of DSUs in 2015. |
• | In 2015, we paid $38,153 for third-party office and other expenses for Mr. Jackson and he received a reserved parking space valued at $5,877. |
TCPL Annual information form 2015 | 82 |
Retainers | Meeting fees | Travel | Other | Totals | ||||||||||
Name | Board ($) | Committee ($) | Committee Chair ($) | Board meetings ($) | Committee meetings ($) | Travel fee ($) | Strategic planning sessions ($) | Fees paid in cash ($) | DSUs credited ($) | Total cash & DSUs credited ($) | ||||
Kevin E. Benson | 70,000 | 9,172 | 6,648 | 15,000 | 12,000 | - | 1,500 | 114,320 | 110,000 | 224,320 | ||||
Derek H. Burney | 70,000 | 5,500 | 12,000 | 13,500 | 12,000 | 9,000 | - | - | 232,000 | 232,000 | ||||
Paule Gauthier (retiring April 29, 2016) | 70,000 | 11,000 | - | 15,000 | 12,000 | 9,000 | 1,500 | 85,000 | 143,500 | 228,500 | ||||
S. Barry Jackson | 201,000 | - | - | - | - | - | - | - | 491,000 | 491,000 | ||||
John Lowe (joined September 9, 2015) | 21,685 | 3,408 | - | 4,500 | 4,500 | 4,500 | - | - | 72,948 | 72,948 | ||||
Paula Rosput Reynolds | 70,000 | 5,500 | 15,000 | 15,000 | 12,000 | 9,000 | 1,500 | 57,250 | 180,750 | 238,000 | ||||
John Richels | 70,000 | 11,000 | - | 15,000 | 10,500 | 9,000 | 1,500 | - | 227,000 | 227,000 | ||||
Mary Pat Salomone | 70,000 | 11,000 | - | 13,500 | 12,000 | 9,000 | 1,500 | 117,000 | 110,000 | 227,000 | ||||
D. Michael G. Stewart | 70,000 | 5,500 | 12,000 | 15,000 | 12,000 | 1,500 | 1,500 | 117,500 | 110,000 | 227,500 | ||||
Siim A. Vanaselja | 70,000 | 7,328 | 13,352 | 15,000 | 7,500 | 10,500 | 1,500 | - | 235,180 | 235,180 | ||||
Richard E. Waugh | 70,000 | 11,000 | - | 15,000 | 12,000 | 7,500 | 1,500 | - | 227,000 | 227,000 |
• | Mr. Lowe, Ms. Reynolds, Mr. Richels and Ms. Salomone received their retainers, meeting fees, travel and other fees in U.S. dollars. Their DSU value is presented in Canadian dollars in this table, but is converted into U.S. dollars when paid. |
• | DSUs credited include all share-based awards vested or earned by the directors in 2015. The minimum portion of the Board retainer paid in DSUs in 2015 was $290,000 for the Chair and $110,000 for the other directors. DSUs credited also includes the portion of the retainers, meeting fees and travel fees directors chose to receive in DSUs in 2015. |
• | Total cash and DSUs credited is the total dollar amount paid for duties performed on the TransCanada and TCPL boards. |
• | DSUs were paid quarterly based on share prices of $54.16, $50.76, $42.20 and $45.19, the closing prices of TransCanada shares on the TSX at the end of each quarter in 2015. Directors are able to redeem their DSUs when they leave the Board. |
TCPL Annual information form 2015 | 83 |
• | DSUs include DSUs credited as dividend equivalents up to January 29, 2016. |
• | Total market value is the market value of TransCanada shares and DSUs, calculated using a closing share price on the TSX of $55.22 on March 2, 2015 and $50.83 on February 23, 2016. It includes DSUs credited as dividend equivalents up to January 29, 2016. |
TCPL Annual information form 2015 | 84 |
At-risk investment | Minimum investment required | |||||||||||||||
Name | Date | Common shares | DSUs | Total common shares and DSUs | Total market value ($) | As a multiple of annual retainer | Total value of minimum investment ($) | Multiple of cash & equity retainer | ||||||||
Kevin E. Benson | 2016 | 13,000 | 61,866 | 74,866 | 3,805,439 | 21.14 | 720,000 | 4x | ||||||||
2015 | 13,000 | 57,059 | 70,059 | 3,868,658 | 21.49 | 720,000 | 4x | |||||||||
Change | - | 4,807 | 4,807 | (63,219 | ) | (0.35 | ) | |||||||||
Derek H. Burney | 2016 | 12,318 | 56,230 | 68,548 | 3,484,295 | 19.36 | 720,000 | 4x | ||||||||
2015 | 10,083 | 49,131 | 59,214 | 3,269,797 | 18.17 | 720,000 | 4x | |||||||||
Change | 2,235 | 7,099 | 9,334 | 214,498 | 1.19 | |||||||||||
Paule Gauthier | 2016 | 2,032 | 63,924 | 65,956 | 3,352,543 | 18.63 | 720,000 | 4x | ||||||||
(retiring April 29, 2016) | 2015 | 1,992 | 58,377 | 60,369 | 3,333,576 | 18.52 | 720,000 | 4x | ||||||||
Change | 40 | 5,547 | 5,587 | 18,967 | 0.11 | |||||||||||
S. Barry Jackson | 2016 | 39,000 | 132,848 | 171,848 | 8,735,034 | 17.79 | 1,964,000 | 4x | ||||||||
2015 | 39,000 | 117,261 | 156,261 | 8,628,732 | 17.57 | 1,964,000 | 4x | |||||||||
Change | - | 15,587 | 15,587 | 106,302 | 0.22 | |||||||||||
John E. Lowe | 2016 | 15,000 | 2,271 | 17,271 | 877,885 | 4.88 | 720,000 | |||||||||
(joined September 9, 2015) | 2015 | - | - | - | - | - | - | |||||||||
Change | 15,000 | 2,271 | 17,271 | 877,885 | 4.88 | |||||||||||
Paula Rosput Reynolds | 2016 | 6,000 | 16,651 | 22,651 | 1,151,350 | 6.40 | 720,000 | 4x | ||||||||
2015 | 4,500 | 11,066 | 15,566 | 859,555 | 4.78 | 720,000 | 4x | |||||||||
Change | 1,500 | 5,585 | 7,085 | 291,795 | 1.62 | |||||||||||
John Richels | 2016 | 10,000 | 13,866 | 23,866 | 1,213,109 | 6.74 | 720,000 | 4x | ||||||||
2015 | 10,000 | 7,148 | 17,148 | 946,913 | 5.26 | 720,000 | 4x | |||||||||
Change | - | 6,718 | 6,718 | 266,196 | 1.48 | |||||||||||
Mary Pat Salomone | 2016 | 2,000 | 8,512 | 10,512 | 534,325 | 2.97 | 720,000 | 4x | ||||||||
2015 | 2,000 | 5,177 | 7,177 | 396,314 | 2.20 | 720,000 | 4x | |||||||||
Change | - | 3,335 | 3,335 | 138,011 | 0.77 | |||||||||||
D. Michael G. Stewart | 2016 | 16,008 | 27,882 | 43,890 | 2,230,929 | 12.39 | 720,000 | 4x | ||||||||
2015 | 15,404 | 24,467 | 39,871 | 2,201,677 | 12.23 | 720,000 | 4x | |||||||||
Change | 604 | 3,415 | 4,019 | 29,252 | 0.16 | |||||||||||
Siim A. Vanaselja | 2016 | 12,000 | 7,898 | 19,898 | 1,011,415 | 5.62 | 720,000 | 4x | ||||||||
2015 | - | 2,701 | 2,701 | 149,149 | 0.83 | — | 4x | |||||||||
Change | 12,000 | 5,197 | 17,197 | 862,266 | 5.62 | |||||||||||
Richard E. Waugh | 2016 | 29,730 | 18,557 | 48,287 | 2,454,428 | 13.64 | 720,000 | 4x | ||||||||
2015 | 29,150 | 13,111 | 42,261 | 2,333,652 | 12.96 | 720,000 | 4x | |||||||||
Change | 580 | 5,446 | 6,026 | 120,776 | 0.67 | |||||||||||
Total | 2016 | 157,088 | 410,505 | 567,593 | 28,850,752 | |||||||||||
2015 | 125,129 | 345,498 | 470,627 | 25,988,023 | ||||||||||||
Change | 31,959 | 65,007 | 96,966 | 2,862,729 |
TCPL Annual information form 2015 | 85 |
Name | Number of shares or units of share- based awards that have not vested (#) | Market or payout value of share-based awards that have not vested ($) | Number of shares or units of vested share-based awards not paid out or distributed (#) | Market or payout value of vested share-based awards not paid out or distributed ($) | Number of share-based awards vested during 2015 | Share-base awards- value vested during 2015 ($) | ||||||
Kevin E. Benson | 654 | 29,554 | 61,212 | 2,766,171 | 4,632 | 209,338 | ||||||
Derek H. Burney | 594 | 26,843 | 55,636 | 2,514,197 | 6,918 | 312,625 | ||||||
Paule Gauthier (retiring April 29, 2016) | 676 | 30,548 | 63,248 | 2,858,206 | 5,362 | 242,334 | ||||||
S. Barry Jackson | 1,404 | 63,447 | 131,443 | 5,939,915 | 15,169 | 685,495 | ||||||
John Lowe (joined September 9, 2015) | 24 | 1,085 | 2,247 | 101,543 | 2,247 | 101,542 | ||||||
Paula Rosput Reynolds | 176 | 7,953 | 16,475 | 744,525 | 5,501 | 248,623 | ||||||
John Richels | 146 | 6,598 | 13,719 | 620,006 | 6,631 | 299,684 | ||||||
Mary Pat Salomone | 90 | 4,067 | 8,422 | 380,610 | 3,288 | 148,587 | ||||||
D. Michael Stewart | 294 | 13,286 | 27,587 | 1,246,679 | 3,326 | 150,307 | ||||||
Siim A. Vanaselja | 83 | 3,751 | 7,814 | 353,143 | 5,136 | 232,106 | ||||||
Richard E. Waugh | 196 | 8,857 | 18,361 | 829,761 | 5,360 | 242,229 |
• | All share-based awards in this chart are DSUs. |
• | The total Market or payout value of share-based awards that have not vested is $195,989 at December 31, 2015. |
• | Shares or Units not vested are dividends declared at December 31, 2015, but not payable until January 29, 2016. Number of shares or units of share based awards that have not vested is calculated using the closing price of TransCanada shares on the TSX at January 29, 2016 ($48.65). |
TCPL Annual information form 2015 | 86 |
Human Resources committee letter to shareholders Dear Shareholder: The Board is holding its seventh consecutive say on pay advisory vote regarding our approach to executive compensation. We are pleased with the level of shareholder support we have received to date and continue to provide comprehensive information to help you with your own decision about the say on pay vote this year. The Executive compensation discussion and analysis (CD&A) section that follows explains how our executive compensation program works and how the Human Resources committee and the Board have assessed our performance in 2015 and made related compensation decisions for each of our named executive officers. TransCanada’s approach to compensation TransCanada’s vision is to be the leading energy infrastructure company in North America, focusing on pipeline and power generation opportunities in regions where we have or can develop a significant competitive advantage. Our strategy is to create value for our shareholders by maximizing the full-life value of our existing infrastructure and commercially developing and building new asset investment programs for future growth. | ||||||
WHERE TO FIND IT | ||||||
> | Human Resources committee letter to shareholders | |||||
> | Executive compensation discussion and analysis | |||||
Executive summary | ||||||
Approach | ||||||
Components | ||||||
Corporate performance | ||||||
Payout of 2013 executive share unit award | ||||||
Executive profiles | ||||||
> | 2015 details | |||||
Summary compensation table | ||||||
Incentive plan awards | ||||||
Equity compensation plan information | ||||||
Retirement benefits | ||||||
Termination and change of control | ||||||
TCPL Annual information form 2015 | 87 |
TCPL Annual information form 2015 | 88 |
![]() | ![]() |
Paula Rosput Reynolds | S. Barry Jackson |
Chair, Human Resources Committee | Chair of the Board of Directors |
TCPL Annual information form 2015 | 89 |
Executive compensation discussion and analysis |
TCPL Annual information form 2015 | 90 |
TCPL Annual information form 2015 | 91 |
2011 | 2012 | 2013 | 2014 | 2015 | ||||||
Total direct compensation awarded to the named executives (as a % of comparable earnings) | 1.1 | % | 1.3 | % | 1.2 | % | 1.1 | % | 1.2 | % |
• | The increase in Total direct compensation awarded to the named executives from 2012 to 2013 is due to base salary adjustments to reflect progression for certain named executives, higher short-term incentive awards due to strong corporate performance, and increases in long-term incentives to more closely align with median levels in the peer group. |
• | Funds generated from operations, Comparable earnings per share, and Comparable earnings are non-GAAP measures and do not have any standardized meanings prescribed by U.S. GAAP (see Appendix B for more information). |
Chart: comparing compensation and financial performance for 2011, 2012, 2013, 2014 and 2015. Fund generated from operations (billions), comparable earnings per share ($ dollars) total direct compensation awarded to the named executives ($ millions). Data by year (IGFO, Comparable Earnings, Total Direct Compensation): 2011 ($3.45, $2.22, $16.5), 2012 ($3.28, $1.89, $16.7), 2013 ($4, $2.24, $19.7) 2014 ($4.27, $2.42, $19.5) 2015 $4.51, $2.48, $20.9 |
TCPL Annual information form 2015 | 92 |
At Dec. 31 | 2010 | 2011 | 2012 | 2013 | 2014 | 2015 | Compound annual return | |||||||||||||
TRP | $100.00 | $122.17 | $134.21 | $143.90 | $175.51 | $144.52 | 7.6 | % | ||||||||||||
TSX | $100.00 | $91.29 | $97.85 | $110.56 | $122.23 | $112.06 | 2.3 | % |
• | The increase in Total direct compensation awarded to the named executives from 2012 to 2013 is due to base salary adjustments to reflect progression for certain named executives, higher short-term incentive awards due to strong corporate performance, and increases in long-term incentives to more closely align with median levels in the peer group. |
Chart for 2011, 2012, 2013, 2014, 2015 of total shareholder return for TransCanada (TRP) and S&P/TSX Composite, Total Returns Index (TSX) compared to Total Direct Compensation awarded to the named executives ($millions). Total direct compensation by year: 2011-$16.5, 2012 - $16.7, 2013 - $19.7, 2014 - $19.5, 2015 - $20.9 |
TCPL Annual information form 2015 | 93 |
TCPL Annual information form 2015 | 94 |
TCPL Annual information form 2015 | 95 |
TCPL Annual information form 2015 | 96 |
Named executive peer group | |
American Electric Power Co. | Imperial Oil Ltd. |
Canadian National Railway Company | Kinder Morgan Inc. |
Canadian Natural Resources Ltd. | NextEra Energy Inc. |
Cenovus Energy Inc. | Occidental Petroleum Corporation |
Dominion Resources Inc. | Pacific Gas & Electric Company |
Enbridge Inc. | Southern Company |
Encana Corporation | Spectra Energy Corp. |
Exelon Corporation | Suncor Energy Inc. |
Fortis Inc. | Talisman Energy Inc. |
Hess Corporation | Teck Resources Ltd. |
Husky Energy Inc. | Williams Companies Inc. |
TCPL Annual information form 2015 | 97 |
Profiles At December 31, 2014 | TransCanada | Peer group | |
Median | 75th percentile | ||
Assets | $58.5 billion | $57.9 billion | $71.2 billion |
Revenue | $10.2 billion | $18.8 billion | $21.1 billion |
Market capitalization at December 31, 2015 (Monthly closing price of shares × shares outstanding for the most recent quarter) | $32.0 billion | $33.3 billion | $51.5 billion |
Employees | 5,971 | 10,200 | 14,400 |
• | Peer group scope information reflects 2014 data, unless otherwise noted, as this is the most current information available. For comparability, the TransCanada scope information also reflects 2014 data. |
TCPL Annual information form 2015 | 98 |
Executive level | Required ownership (multiple of base salary) |
Chief Executive Officer | 5x |
Executive Vice-Presidents | 2x |
Senior Vice-Presidents | 1x |
TCPL Annual information form 2015 | 99 |
Element | Form | Performance period | Objective |
base salary (fixed) | cash | • one year | • provide base compensation commensurate with the role • attract and retain executives |
short-term incentive (variable) | cash | • one year | • motivate executives to achieve key annual business objectives • reward executives for relative contribution to TransCanada • align interests of executives and shareholders • attract and retain executives |
long-term incentive (variable) | ESUs | • three-year term • vesting at the end of the term • awards subject to a performance multiplier based on pre-established targets | • motivate executives to achieve medium-term business objectives • align interests of executives and shareholders • attract and retain executives |
stock options | • seven-year term • one third vest each year beginning on the first anniversary of the grant date | • motivate executives to achieve long-term sustainable business objectives • align interests of executives and shareholders • attract and retain executives |
TCPL Annual information form 2015 | 100 |
( | ) | ( | ) | |||||||||||||||
Base salary | x | Short-term incentive target | x | Business/functional and individual performance factor | x | Business/functional and individual weighting | + | Corporate performance factor | x | Corporate weighting | = | Short-term incentive award ($) | ||||||
TCPL Annual information form 2015 | 101 |
Short-term incentive target (% of base salary) | Performance weighting | |||||||||||
2015 | 2016 | |||||||||||
Corporate | Business/functional and individual | Corporate | Business unit | Individual | ||||||||
President & Chief Executive Officer(Russell K. Girling) | 100 | % | 100 | % | _ | 100 | % | _ | _ | |||
Executive Vice-President, Corporate Development & Chief Financial Officer (Donald R. Marchand) | 65 | % | 50 | % | 50 | % | 60 | % | _ | 40 | % | |
Chief Operating Officer (Alexander J. Pourbaix) | 75 | % | 50 | % | 50 | % | 80 | % | _ | 20 | % | |
Executive Vice-President & President, Natural Gas Pipelines (Karl Johannson) | 65 | % | 50 | % | 50 | % | 40 | % | 40 | % | 20 | % |
Executive Vice-President & President, Energy (William C. Taylor) | 65 | % | 50 | % | 50 | % | 40 | % | 40 | % | 20 | % |
TCPL Annual information form 2015 | 102 |
Number of ESUs vesting | x | Valuation price on the vesting date | x | Performance multiplier | = | ESU payout ($) |
• | Number of ESUs vesting is the number of ESUs originally granted plus ESUs earned as dividend equivalents during the three-year performance period. |
• | Valuation price on the vesting date is the volume- weighted average closing price of TransCanada shares for the 20 trading days immediately prior to and including the vesting date (December 31). |
Performance measure | Weighting | Measurement period |
Relative TSR against the S&P/TSX 60 | 25% | January 1, 2016 to December 31, 2018 |
Relative TSR against the ESU peer group | 25% | |
Comparable earnings per share | 50% |
2016 ESU grant peer group for relative TSR | ||
AltaGas Ltd. | Enbridge Inc. | Pembina Pipeline Corp. |
Canadian Utilities Ltd. | Enterprise Products Partners L.P. | Sempra Energy |
CenterPoint Energy Inc. | Fortis Inc. | Spectra Energy Corp. |
Dominion Resources Inc. | Inter Pipeline Ltd. | Veresen Inc. |
Emera Inc. | Kinder Morgan Inc. | Williams Companies Inc. |
TCPL Annual information form 2015 | 103 |
If TransCanada’s relative TSR is | Then the performance multiplier is | |
At or below the 25th percentile of the ESU peer group (threshold) | 0.50 | We calculate the performance multiplier using a straight-line interpolation if performance is between: • threshold and target, or • target and maximum |
At the 50th percentile of the ESU peer group (target) | 1.00 | |
At or above the 75th percentile of the ESU peer group (maximum) | 1.50 |
• | the shares are consolidated, subdivided, converted, exchanged, reclassified or in any way substituted, or |
• | a stock dividend that is not in place of an ordinary course cash dividend is paid on the shares. |
TCPL Annual information form 2015 | 104 |
• | clarify an item |
• | correct an error or omission |
• | change the vesting date of an existing grant, or |
• | change the expiry date of an outstanding option to an earlier date. |
• | increasing the number of shares available for issue under the plan |
• | lowering the exercise price of a previously granted option |
• | canceling and reissuing an option |
• | permitting options to be transferable or assignable other than for normal estate settlement purposes |
• | changing the categories of individuals eligible to participate in the plan |
• | providing financial assistance to a participant in connection with the exercise of options, or |
• | extending the expiry date of an option. |
TCPL Annual information form 2015 | 105 |
( | ) | |||||||
1.25% of employee's highest average earnings (up to the final average YMPE) | + | 1.75% of employee's highest average earnings (above the final average YMPE) | x | Credited service | = | Annual retirement benefit ($) | ||
• | Highest average earnings is the average of an employee’s best 36 consecutive months of pensionable earnings in their last 15 years of employment. Pensionable earnings means an employee’s base salary plus the annual short-term incentive award up to a pre-established maximum, expressed as a percentage of base salary. For 2015, this is 100 per cent for the CEO, and between 60 to 75 per cent for the other named executives. Pensionable earnings do not include any other forms of compensation. |
• | YMPE is the Year’s Maximum Pensionable Earnings under the Canada/Québec Pension Plan. |
• | Final average YMPE is the average of the YMPE in effect for the latest calendar year from which earnings are included in Employees’ highest average earnings calculation plus the two previous years. |
• | Credited service is the employee’s years of credited pensionable service in the plan. Registered DB plans are subject to a maximum annual benefit accrual under the Income Tax Act (Canada). As this is currently $2,890 for each year of credited service, participants cannot earn benefits in the registered plan on any compensation that is higher than approximately $180,000 per year. |
TCPL Annual information form 2015 | 106 |
• | monthly pension for life, and 60 per cent is paid to the spouse after the employee dies, or |
• | if the employee is not married, the monthly pension is paid to the employee’s beneficiary or estate for the balance of the 10 years, if the employee dies within 10 years of retirement. |
• | increasing the percentage of the pension value that continues after they die |
• | adding a guarantee period to the pension, or |
• | transferring the lump sum commuted value of the registered pension plan to a locked-in retirement account up to certain tax limits and the excess is paid in cash. Subject to company discretion, the supplemental pension plan commuted value may also be transferred and paid in cash. |
• | a flexible perquisite allowance of $4,500 that the named executive can use at his discretion |
• | a limited number of luncheon and/or recreational club memberships, based on business needs |
• | a reserved parking space valued at $5,877, and |
• | an annual car allowance of $18,000. |
TCPL Annual information form 2015 | 107 |
2015 target | 2015 result | Rating (0-2.0) | Weighting | Factor | |||||
1. Maximized 2015 financial performance | |||||||||
Comparable earnings per share | $2.55 | $2.48 | 1.5 | 20 | % | 0.3 | |||
Funds generated from operations (millions) | $4,267 | $4,513 | |||||||
2. Maximized the full life value of our infrastructure assets and commercial positions | |||||||||
Safety and asset integrity | Various targets | Exceeded | 1.2 | 10 | % | 0.1 | |||
Maximized long-term value of base business | $100 million of incremental long-term value | Exceeded | 1.5 | 20 | % | 0.3 | |||
3. Commercially developed and physically executed new asset investment programs | |||||||||
Advanced major projects | Various targets | Not met | 0 | 20 | % | 0 | |||
4. Cultivated a focused portfolio of high quality development opportunities | |||||||||
New opportunities | $3-$5 billion | Exceeded | 2.0 | 15 | % | 0.3 | |||
5. Maximized and maintained financial and organizational capacity and flexibility | |||||||||
Fund capital projects | Funding on compelling terms, leverage portfolio management | Exceeded | 1.2 | 15 | % | 0.2 | |||
Overall Corporate factor (1. + 2. + 3. + 4. + 5.) | 100 | % | 1.2 |
Net (loss)/income per common share | $ | (1.75 | ) |
Keystone XL impairment charge | 4.08 | ||
Other asset valuation adjustments | 0.18 | ||
Non-controlling interests (TC PipeLines, LP-Great Lakes impairment) | (0.28 | ) | |
Restructuring costs | 0.10 | ||
Bruce Power merger - debt retirement charge | 0.04 | ||
Risk management activities | 0.06 | ||
Alberta corporate income tax rate increase | 0.05 | ||
Comparable earnings per share | $2.48 |
• | We calculate both Net income per share and Comparable earnings per share based on the weighted average number of our shares outstanding (709 million in 2015). |
• | Funds generated from operations and Comparable earnings per share are non-GAAP measures and do not have any standardized meaning as prescribed by U.S. GAAP (see Appendix B for more information). |
TCPL Annual information form 2015 | 108 |
TCPL Annual information form 2015 | 109 |
Key performance areas | 2015 Results |
Maximized 2015 financial performance | • Comparable earnings per share were slightly below target largely due to lower Western power prices, partially offset by higher U.S. gas pipelines and Bruce Power revenues • In determining the financial performance rating, the Board excluded the impact of "non-comparable earnings" that are not related to the underlying operations of the business in the year. • Funds generated from operations were higher than target as a result of lower pension funding requirements, realized mark-to-market positions and higher distributions from investments. |
Maximized and maintained financial and organizational capacity and flexibility Maximized the full life value of our infrastructure assets and commercial positions | • We achieved some of our safety measures for both our employees and contractors, but did not meet some others mainly due to minor vehicle incidents. • We exceeded our overall targets for asset integrity (pipeline leaks and ruptures). • We raised over $6 billion in debt and subordinated capital at very attractive rates. We prudently managed our capital structure to preserve our solid credits ratings. A strong balance sheet and access to capital markets is critical to our ability to execute our growth portfolio. • We secured contracts and incentive arrangements and achieved cost reductions that will add significant operating earnings and cash flows in future years. |
Commercially developed and physically executed new asset investment programs Cultivated a focused portfolio of high quality development opportunities | • We placed $0.6 billion of assets into service in 2015. • Notable progress was made in 2015 on our industry-leading portfolio of commercially secured projects, which now totals $58 billion and includes $13 billion in near term projects that are expected to drive earnings and cash flow growth as they come on stream through 2018. • We captured over $10 billion in new pipeline and power opportunities throughout the year and advanced several key projects through the permitting phases and into construction. |
TCPL Annual information form 2015 | 110 |
Measure | Period | Performance level targets for 2013 ESU award | Actual performance | Multiplier | |||
Threshold | Target | Maximum | |||||
Relative TSR against the peer group (see below) | January 2013 to December 2015 | at or below the 25th percentile | 50th percentile | at least the 75th percentile | P27 | 0.54 | |
• | Relative TSR is calculated using $44.90, the twenty-day volume weighted average closing price of TransCanada shares on the TSX at December 31, 2015. Our absolute TSR performance was 9.05 per cent. |
2013 ESU grant peer group for relative TSR | |||
Canadian Utilities Ltd. | Enbridge Inc. | Sempra Energy | |
Dominion Resources Inc. | Entergy Corporation | Southern Company | |
DTE Energy Co. | Exelon Corporation | Spectra Energy Corporation | |
Duke Energy Corporation | Fortis Inc. | TransAlta Corporation | |
Emera Inc. | Pacific Gas & Electric Company | Xcel Energy Inc. | |
TCPL Annual information form 2015 | 111 |
2013 ESU award | 2013 ESU payout | ||||||||||
Number of ESUs granted | Value of ESU award ($) | Number of ESUs vesting (includes dividend equivalents to December 31, 2015) | Performance multiplier | Value of ESU payout ($) | % of original award | ||||||
Russell K. Girling | 63,856.960 | 3,000,000 | 71,823.641 | 0.54 | 1,741,436 | 58 | % | ||||
Donald R. Marchand | 15,073.031 | 708,131 | 16,953.518 | 411,055 | |||||||
Alexander J. Pourbaix | 26,979.566 | 1,267,500 | 30,345.500 | 735,757 | |||||||
Karl Johannson | 11,880.268 | 558,135 | 13,362.410 | 323,985 | |||||||
William C. Taylor | 6,385.696 | 308,970 | 7,182.380 | 198,411 |
• | Number of ESUs granted is the value of the ESU award divided by the valuation price of $46.98 (the volume-weighted average closing price of TransCanada shares on the TSX for the five trading days immediately prior to and including the grant date (January 1, 2013)). |
• | Number of ESUs vesting includes an equivalent number of units for the final dividend that is declared as of December 31, 2015 but which has not been paid at the vesting date. The final dividend value is awarded in cash and has been converted to units and is reflected under Number of ESUs vesting. |
• | Value of ESU payout is calculated using the valuation price of $44.90 (the volume-weighted average closing price of TransCanada shares on the TSX for the twenty trading days immediately prior to and including the vesting date (December 31, 2015)). |
TCPL Annual information form 2015 | 112 |
![]() | Russell K. Girling | ||||||||||||||
PRESIDENT AND CHIEF EXECUTIVE OFFICER | |||||||||||||||
Mr. Girling is responsible for our overall leadership and vision in developing with our Board our strategic direction, values and business plans. This includes overall responsibility for operating and growing our business while managing risk to create long-term sustainable value for our shareholders. | |||||||||||||||
2015 Key results • Record earnings and funds generated from operations • Secured approximately $10 billion of contracted or rate-regulated new infrastructure projects that support future growth • Advanced development of major projects including Energy East, B.C. west coast LNG-related projects • Led Business Transformation organizational restructuring that improved efficiency and effectiveness • Provided visible leadership consistent with TransCanada's values • Keystone XL permit denial | • Mr. Girling’s short-term incentive award was based 100 per cent on corporate performance. • The short-term incentive award for 2015 performance was based on Mr. Girling’s target of 100 per cent of base salary. • Mr. Girling’s 2015 short-term and long-term incentive awards as a percentage of 2015 base salary were 120 per cent and 431 per cent, respectively. | ||||||||||||||
Compensation (as at December 31) | 2015 | 2014 | 2013 | ||||||||||||
Fixed | |||||||||||||||
Base salary | $1,300,008 | $1,300,008 | $1,300,008 | ||||||||||||
Variable | |||||||||||||||
Short-term incentive | 1,560,000 | 1,690,000 | 1,950,000 | ||||||||||||
Long-term incentive | |||||||||||||||
ESUs | 2,800,000 | 2,437,500 | 3,000,000 | ||||||||||||
Stock options | 2,800,000 | 2,437,500 | 2,200,000 | ||||||||||||
Total direct compensation | $8,460,008 | $7,865,008 | $8,450,008 | ||||||||||||
Change from last year | 8 | % | -7 | % | — | ||||||||||
2015 Pay mix | |||||||||||||||
![]() | |||||||||||||||
Short-term incentive is attributed to the noted financial year, and is paid by March 15 of the following year. Share ownership is based on the 20-day volume-weighted average closing price on the TSX of $44.90 for TransCanada shares as at December 31, 2015. | Share ownership | ||||||||||||||
Minimum level of ownership | Minimum value | Ownership under the guidelines | |||||||||||||
TransCanada shares | Total ownership as a multiple of base salary | ||||||||||||||
5x | $6,500,040 | $6,651,755 | 5.1x | ||||||||||||
Photo of Russell K. Girling |
TCPL Annual information form 2015 | 113 |
![]() | Donald R. Marchand | ||||||||||||||
EXECUTIVE VICE-PRESIDENT, CORPORATE DEVELOPMENT AND CHIEF FINANCIAL OFFICER (Executive Vice-President and Chief Financial Officer to September 30, 2015) | |||||||||||||||
Mr. Marchand is responsible for all corporate financial affairs of the company including financial reporting, taxation, finance, treasury, risk management and investor relations. He is also responsible for our corporate strategy process and corporate development activities. | |||||||||||||||
2015 Key results • Maintained “A” grade credit rating • Completed over $6 billion of financing on favorable terms • Maintained excellent communication with the investment community • Establishment of Normal Course Issuer Bid program and repurchase of common shares • Oversaw strong financial control environment | • Mr. Marchand’s short-term incentive award was based on a combination of corporate performance (50 per cent) and functional unit performance (50 per cent). • The short-term incentive award for 2015 performance was based on Mr. Marchand’s target of 65 per cent of base salary. • Mr. Marchand’s 2015 short-term and long-term incentive awards as a percentage of 2015 base salary were 78 per cent and 325 per cent, respectively. | ||||||||||||||
Compensation (as at December 31) | 2015 | 2014 | 2013 | ||||||||||||
Fixed | |||||||||||||||
Base salary | $575,004 | $530,004 | $515,004 | ||||||||||||
Variable | |||||||||||||||
Short-term incentive | 448,550 | 465,100 | 525,000 | ||||||||||||
Long-term incentive | |||||||||||||||
ESUs | 934,375 | 861,250 | 708,131 | ||||||||||||
Stock options | 934,375 | 861,250 | 708,130 | ||||||||||||
Total direct compensation | $2,892,304 | $2,717,604 | $2,456,265 | ||||||||||||
Change from last year | 6 | % | 11 | % | — | ||||||||||
2015 Pay mix | |||||||||||||||
![]() | |||||||||||||||
Short-term incentive is attributed to the noted financial year, and is paid by March 15 of the following year. Share ownership is based on the 20-day volume-weighted average closing price on the TSX of $44.90 for TransCanada shares as at December 31, 2015. | Share ownership | ||||||||||||||
Minimum level of ownership | Minimum value | Ownership under the guidelines | |||||||||||||
TransCanada shares | Total ownership as a multiple of base salary | ||||||||||||||
2x | $1,150,008 | $927,948 | 1.6x | ||||||||||||
Per the amendments approved in 2015 (page 83), Mr. Marchand has until the end of 2020 to replace the value previously satisfied through unvested ESUs. | |||||||||||||||
Photo of Donald R. Marchand |
TCPL Annual information form 2015 | 114 |
![]() | Alexander J. Pourbaix | ||||||||||||||
CHIEF OPERATING OFFICER (Executive Vice-President and President, Development to September 30, 2015) | |||||||||||||||
Mr. Pourbaix is accountable for the profitability and growth of all of TransCanada's business units as well as the operations and projects centre of excellence. | |||||||||||||||
2015 Key results • Fostered safety culture • Placed $0.6 billion of assets into service in 2015 • Advanced major projects, including Energy East and B.C. west coast LNG-related projects • Leadership on Business Transformation organizational restructuring that improved efficiency and effectiveness • Keystone XL permit denial | • Mr. Pourbaix’s short-term incentive award was based on a combination of corporate performance (50 per cent) and business unit performance (50 per cent). • The short-term incentive award for 2015 performance was based on Mr. Pourbaix’s target of 75 per cent of base salary. • Mr. Pourbaix’s 2015 short-term and long-term incentive awards as a percentage of 2015 base salary were 94 per cent and 400 per cent, respectively. | ||||||||||||||
Compensation (as at December 31) | 2015 | 2014 | 2013 | ||||||||||||
Fixed | |||||||||||||||
Base salary | $800,004 | $800,004 | $780,000 | ||||||||||||
Variable | |||||||||||||||
Short-term incentive | 750,050 | 810,050 | 975,000 | ||||||||||||
Long-term incentive | |||||||||||||||
ESUs | 1,600,000 | 1,400,000 | 1,267,500 | ||||||||||||
Stock options | 1,600,000 | 1,400,000 | 1,267,500 | ||||||||||||
Total direct compensation | $4,750,054 | $4,410,054 | $4,290,000 | ||||||||||||
Change from last year | 8 | % | 3 | % | — | ||||||||||
2015 Pay mix | |||||||||||||||
![]() | |||||||||||||||
Short-term incentive is attributed to the noted financial year, and is paid by March 15 of the following year. Share ownership is based on the 20-day volume-weighted average closing price on the TSX of $44.90 for TransCanada shares as at December 31, 2015. | Share ownership | ||||||||||||||
Minimum level of ownership | Minimum value | Ownership under the guidelines | |||||||||||||
TransCanada shares | Total ownership as a multiple of base salary | ||||||||||||||
2x | $1,600,008 | $2,739,618 | 3.4x | ||||||||||||
Photo of Alexander J. Pourbaix |
TCPL Annual information form 2015 | 115 |
![]() | Karl Johannson | ||||||||||||||
EXECUTIVE VICE-PRESIDENT AND PRESIDENT, NATURAL GAS PIPELINES | |||||||||||||||
Mr. Johannson is responsible for the profitability and growth of our natural gas pipeline and regulated natural gas storage businesses in Canada, the United States and Mexico. | |||||||||||||||
2015 Key results • Strong financial results from natural gas pipeline business • Awarded the contract to build, own and operate the Tuxpan-Tula pipeline in Mexico • NEB approval of the NGTL System's $1.7 billion North Montney Mainline Project • NEB approval of the Kings North Connection Project which enables shippers to source growing supplies of Marcellus gas • Agreement with eastern LDC's that resolves their issues with Energy East and the Eastern Mainline Project • NEB approval, as filed, of compliance filing for LDC settlement tolls • 2.7 BCF/d of new firm natural gas transportation service that will require a further $600 million expansion of the NGTL system | • Mr. Johannson’s short-term incentive award was based on a combination of corporate performance (50 per cent) and business unit performance (50 per cent). • The short-term incentive award for 2015 performance was based on Mr. Johannson’s target of 65 per cent of base salary. • Mr. Johannson’s 2015 short-term and long-term incentive awards as a percentage of 2015 base salary were 85 per cent and 300 per cent, respectively. | ||||||||||||||
Compensation (as at December 31) | 2015 | 2014 | 2013 | ||||||||||||
Fixed | |||||||||||||||
Base salary | $575,004 | $550,008 | $475,008 | ||||||||||||
Variable | |||||||||||||||
Short-term incentive | 485,900 | 518,400 | 500,000 | ||||||||||||
Long-term incentive | |||||||||||||||
ESUs | 862,500 | 756,250 | 558,135 | ||||||||||||
Stock options | 862,500 | 756,250 | 558,134 | ||||||||||||
Total direct compensation | $2,785,904 | $2,580,908 | $2,091,277 | ||||||||||||
Change from last year | 8 | % | 23 | % | — | ||||||||||
2015 Pay mix | |||||||||||||||
![]() | |||||||||||||||
Short-term incentive is attributed to the noted financial year, and is paid by March 15 of the following year. Share ownership is based on the 20-day volume-weighted average closing price on the TSX of $44.90 for TransCanada shares as at December 31, 2015. | Share ownership | ||||||||||||||
Minimum level of ownership | Minimum value | Ownership under the guidelines | |||||||||||||
TransCanada shares | Total ownership as a multiple of base salary | ||||||||||||||
2x | $1,150,008 | $1,221,370 | 2.1x | ||||||||||||
Photo of Karl Johannson |
TCPL Annual information form 2015 | 116 |
![]() | William C. Taylor | ||||||||||||||
EXECUTIVE VICE-PRESIDENT AND PRESIDENT, ENERGY | |||||||||||||||
Mr. Taylor is responsible for the profitability and growth of our power and non-regulated gas storage business in Canada and the United States. | |||||||||||||||
2015 Key results • Lower than targeted financial results due largely to lower Western power prices • Agreement to extend the operating life of the Bruce Power facility to 2064 and acquired additional ownership interest in this facility • Acquisition of Ironwood power plant • Agreement allowing for dispatch of up to 570 MW of firm peak winter capacity for a term of 20 years | • Mr. Taylor’s short-term incentive award was based on a combination of corporate performance (50 per cent) and functional unit performance (50 per cent). • The short-term incentive award for 2015 performance was based on Mr. Taylor's target of 65 per cent of base salary. • Mr. Taylor's 2015 short-term and long-term incentive awards as a percentage of 2015 base salary were 85 per cent and 260 per cent, respectively. | ||||||||||||||
Compensation (as at December 31) | 2015 | 2014 | 2013 | ||||||||||||
Fixed | |||||||||||||||
Base salary | $450,000 | $400,008 | $365,623 | ||||||||||||
Variable | |||||||||||||||
Short-term incentive | 380,250 | 355,713 | 504,651 | ||||||||||||
Long-term incentive | |||||||||||||||
ESUs | 585,000 | 441,800 | 308,970 | ||||||||||||
Stock options | 585,000 | 441,800 | 154,485 | ||||||||||||
Total direct compensation | $2,000,250 | $1,639,321 | $1,333,729 | ||||||||||||
Change from last year | 22 | % | 23 | % | — | ||||||||||
The values provided to Mr. Taylor in U.S. dollars have been expressed in Canadian dollars based on the Bank of Canada's average annual exchange rate for the financial year noted, namely 1.0299 for 2013, 1.1045 for 2014, and 1.2787 for 2015. | |||||||||||||||
2015 Pay mix | |||||||||||||||
![]() | |||||||||||||||
Short-term incentive is attributed to the noted financial year, and is paid by March 15 of the following year. Share ownership is based on the 20-day volume-weighted average closing price on the TSX of $44.90 for TransCanada shares as at December 31, 2015. | Share ownership | ||||||||||||||
Minimum level of ownership | Minimum value | Ownership under the guidelines | |||||||||||||
TransCanada shares | Total ownership as a multiple of base salary | ||||||||||||||
2x | $900,000 | $452,143 | 1.0x | ||||||||||||
Per the amendments approved in 2015 (page 83), Mr. Taylor has until the end of 2020 to replace the value previously satisfied through unvested ESUs. |
Photo of Bill Taylor |
TCPL Annual information form 2015 | 117 |
Executive compensation – 2015 details |
Non-equity incentive plan compensation | |||||||||||||||||
Name and principal position | Year | Salary ($) | Share- based awards ($) | Option- based awards ($) | Annual incentive plans ($) | Long-term incentive plans ($) | Pension value ($) | All other compensation ($) | Total compensation ($) | ||||||||
Russell K. Girling | 2015 | 1,300,008 | 2,800,000 | 2,800,000 | 1,560,000 | — | 326,000 | 13,000 | 8,799,008 | ||||||||
President & Chief Executive Officer | 2014 | 1,300,008 | 2,437,500 | 2,437,500 | 1,690,000 | — | 224,000 | 13,000 | 8,102,008 | ||||||||
2013 | 1,300,008 | 3,000,000 | 2,200,000 | 1,950,000 | — | 217,000 | 33,001 | 8,700,009 | |||||||||
Donald R. Marchand | 2015 | 567,504 | 934,375 | 934,375 | 448,550 | — | 454,000 | 13,829 | 3,352,633 | ||||||||
Executive Vice-President, Corporate Development & Chief Financial Officer | 2014 | 527,504 | 861,250 | 861,250 | 465,100 | — | 165,000 | 23,102 | 2,903,206 | ||||||||
2013 | 505,838 | 708,131 | 708,130 | 525,000 | — | 476,000 | 6,717 | 2,929,816 | |||||||||
Alexander J. Pourbaix | 2015 | 800,004 | 1,600,000 | 1,600,000 | 750,050 | — | 179,000 | 20,308 | 4,949,362 | ||||||||
Chief Operating Officer | 2014 | 796,670 | 1,400,000 | 1,400,000 | 810,050 | — | 725,000 | 19,967 | 5,151,687 | ||||||||
2013 | 777,500 | 1,267,500 | 1,267,500 | 975,000 | — | 204,000 | 52,775 | 4,544,275 | |||||||||
Karl Johannson | 2015 | 570,838 | 862,500 | 862,500 | 485,900 | — | 301,000 | 12,055 | 3,094,793 | ||||||||
Executive Vice-President & President, Natural Gas Pipelines | 2014 | 537,508 | 756,250 | 756,250 | 518,400 | — | 580,000 | 43,741 | 3,192,149 | ||||||||
2013 | 473,340 | 558,135 | 558,134 | 500,000 | — | 142,000 | 8,310 | 2,239,919 | |||||||||
William C. Taylor | 2015 | 441,668 | 585,000 | 585,000 | 380,250 | — | 530,000 | 385,819 | 2,907,737 | ||||||||
Executive Vice-President & President, Energy | 2014 | 421,546 | 441,800 | 441,800 | 355,713 | — | 848,000 | 369,868 | 2,878,727 | ||||||||
2013 | 364,646 | 308,970 | 154,485 | 504,651 | — | 79,000 | 91,672 | 1,503,424 | |||||||||
• | Mr. Marchand was appointed Executive Vice-President, Corporate Development and Chief Financial Officer on October 1, 2015. Amounts shown for 2015 include compensation earned for three months in his new position and nine months in his previous position as Executive Vice-President and Chief Financial Officer. |
• | Mr. Pourbaix was appointed Chief Operating Officer on October 1, 2015. Amounts shown for 2015 include compensation earned for three months in his new position and nine months in his previous position as Executive Vice-President and President, Development. |
• | The values provided to Mr. Taylor in U.S. dollars have been expressed in Canadian dollars based on the Bank of Canada's average annual exchange rate for the financial year noted, namely 1.0299 for 2013, 1.1045 for 2014, and 1.2787 for 2015. |
• | Salary is the actual base salary earned during each of the three years. |
• | Share-based awards is the long-term incentive compensation that was awarded as ESUs. The number of ESUs granted is the value of the ESU award divided by the volume-weighted average closing price of TransCanada shares for the five trading days (twenty for the 2015 grant) immediately prior to and including the grant date: $54.64 in 2015, $48.55 in 2014, and $46.98 in 2013. |
• | Option-based awards is the long-term incentive compensation that was awarded as stock options. The exercise price is the closing market price of TransCanada shares on the TSX on the trading day immediately prior to the grant date: $56.58 in 2015, $49.03 in 2014, and $47.09 in 2013. See Stock option valuation below for more information. |
• | Annual incentive plans is the short-term incentive award, paid as an annual cash bonus and attributable to the noted financial year. Payments are made in the first quarter of the following year. |
• | There are no long-term non-equity incentive plans. |
• | Pension value includes the annual compensatory value from the DB pension plan. The annual compensatory value is the compensatory change in the accrued obligation and includes the service cost to TransCanada in 2015, plus compensation changes that were higher or lower than the base salary assumptions, and plan changes. See Retirement benefits below for more information. |
TCPL Annual information form 2015 | 118 |
• | All other compensation includes other compensation not reported in any other column for each named executive and includes: |
• | payments to the named executives by any of our subsidiaries and affiliates (including directors’ fees paid by affiliates and amounts paid for serving on management committees of entities that we hold an interest in). These include: |
2015 | 2014 | 2013 | ||
Mr. Pourbaix | $ — | $12,000 | $45,000 | |
Mr. Taylor | 48,000 | 31,500 | — | |
• | matching contributions we made on behalf of the named executives under the employee stock savings plan: |
2015 | 2014 | 2013 | ||
Mr. Girling | $13,000 | $13,000 | $13,000 | |
Mr. Marchand | 5,675 | 5,275 | 5,058 | |
Mr. Pourbaix | 8,000 | 7,967 | 7,775 | |
Mr. Johannson | 5,708 | 5,375 | 4,733 | |
• | cash payments if the named executive elected to receive payment in lieu of vacation entitlement from the previous year: |
2015 | 2014 | 2013 | |||
Mr. Girling | $ — | $ — | $20,001 | ||
Mr. Marchand | 8,154 | 17,827 | 1,659 | ||
Mr. Pourbaix | 12,308 | — | — | ||
Mr. Johannson | 6,346 | 38,366 | 3,577 | ||
Mr. Taylor | 22,309 | 1,508 | 300 | ||
• | payments, taxes, and gross-ups related to relocation, pension, and financial counseling made on behalf of a named executive include: |
2015 | 2014 | 2013 | |
Mr. Taylor | $315,510 | $336,860 | $91,372 |
• | Perquisites in 2015, 2014, and 2013 are not included because they are less than $50,000 and 10 per cent of each named executive's total base salary. |
TCPL Annual information form 2015 | 119 |
Grant date | Exercise price ($) | Compensation value of each stock option ($) |
February 19, 2015 | 56.58 | 6.45 |
February 25, 2014 | 49.03 | 5.54 |
February 15, 2013 | 47.09 | 5.74 |
Total stock options exercised (#) | Total value realized ($) | |||
Russell K. Girling | 83,857 | 1,388,367 | ||
Donald R. Marchand | — | — | ||
Alexander J. Pourbaix | 120,929 | 1,841,535 | ||
Karl Johannson | 18,000 | 308,946 | ||
William C. Taylor | 15,000 | 215,550 |
TCPL Annual information form 2015 | 120 |
Option-based awards | Share-based awards | ||||||||||||
Name | Number of securities underlying unexercised options (#) | Option exercise price ($) | Option expiration date | Value of unexercised in-the-money options ($) | Number of shares or units of shares that have not vested (#) | Market or payout value of share-based awards that have not vested ($) | Market or payout value of vested share-based awards not paid out or distributed ($) | ||||||
Russell K. Girling | 100,000 | 31.97 | 23-Feb-2016 | 1,322,000 | 107,773 | 2,435,131 | — | ||||||
100,000 | 31.93 | 14-Sept-2016 | 1,326,000 | ||||||||||
133,080 | 35.08 | 26-Feb-2017 | 1,345,439 | ||||||||||
100,000 | 36.90 | 16-Jun-2017 | 829,000 | ||||||||||
158,172 | 37.93 | 18-Feb-2018 | 1,148,329 | ||||||||||
385,475 | 41.95 | 17-Feb-2019 | 1,248,939 | ||||||||||
383,275 | 47.09 | 15-Feb-2020 | — | ||||||||||
439,982 | 49.03 | 25-Feb-2021 | — | ||||||||||
434,109 | 56.58 | 19-Feb-2022 | — | ||||||||||
Donald R. Marchand | 47,500 | 36.26 | 29-Jul-2017 | 424,175 | 37,030 | 836,693 | — | ||||||
30,756 | 37.93 | 18-Feb-2018 | 223,289 | ||||||||||
96,369 | 41.95 | 17-Feb-2019 | 312,236 | ||||||||||
123,368 | 47.09 | 15-Feb-2020 | — | ||||||||||
155,460 | 49.03 | 25-Feb-2021 | — | ||||||||||
144,864 | 56.58 | 19-Feb-2022 | — | ||||||||||
Alexander J. Pourbaix | 95,057 | 35.08 | 26-Feb-2017 | 961,026 | 61,744 | 1,395,106 | — | ||||||
27,500 | 36.26 | 29-Jul-2017 | 245,575 | ||||||||||
97,540 | 37.93 | 18-Feb-2018 | 708,140 | ||||||||||
213,687 | 41.95 | 17-Feb-2019 | 692,346 | ||||||||||
220,819 | 47.09 | 15-Feb-2020 | — | ||||||||||
252,708 | 49.03 | 25-Feb-2021 | — | ||||||||||
248,062 | 56.58 | 19-Feb-2022 | — | ||||||||||
Karl Johannson | 19,011 | 35.08 | 26-Feb-2017 | 192,201 | 33,319 | 752,843 | — | ||||||
18,348 | 37.93 | 18-Feb-2018 | 133,206 | ||||||||||
32,899 | 41.95 | 17-Feb-2019 | 106,593 | ||||||||||
48,450 | 45.29 | 2-Nov-2019 | — | ||||||||||
97,236 | 47.09 | 15-Feb-2020 | — | ||||||||||
136,507 | 49.03 | 25-Feb-2021 | — | ||||||||||
133,721 | 56.58 | 19-Feb-2022 | — | ||||||||||
William C. Taylor | 15,209 | 35.08 | 26-Feb-2017 | 153,763 | 20,083 | 453,775 | — | ||||||
16,487 | 37.93 | 18-Feb-2018 | 119,696 | ||||||||||
26,071 | 41.95 | 17-Feb-2019 | 84,470 | ||||||||||
26,132 | 47.09 | 15-Feb-2020 | — | ||||||||||
72,202 | 49.03 | 25-Feb-2021 | — | ||||||||||
90,698 | 56.58 | 19-Feb-2022 | — |
TCPL Annual information form 2015 | 121 |
• | Value of unexercised in-the-money options is based on outstanding vested and unvested stock options and the difference between the option exercise price and year-end closing price of our shares. |
• | Number of shares or units of shares that have not vested includes the amount of the grant, plus reinvested units earned as dividend equivalents of all outstanding ESUs as at December 31, 2015. |
• | Market or payout value of share-based awards that have not vested is the minimum payout value of all outstanding ESUs as at December 31, 2015. The value is calculated by multiplying 50 per cent of the number of units that have not vested by the year-end closing price of our shares. |
• | No value is shown for Market or payout value of vested share-based awards not paid out or distributed. The ESU award granted in 2013 vested on December 31, 2015, and will be paid in March 2016. These awards are shown in the next table. |
Name | Option-based awards – value vested during the year ($) | Share-based awards – value vested during the year ($) | Non-equity incentive plan compensation – value earned during the year ($) | |||
Russell K. Girling | 4,000,666 | 1,741,436 | 1,560,000 | |||
Donald R. Marchand | 1,173,907 | 411,055 | 448,550 | |||
Alexander J. Pourbaix | 2,261,370 | 735,757 | 750,050 | |||
Karl Johannson | 734,682 | 323,985 | 485,900 | |||
William C. Taylor | 348,507 | 198,411 | 380,250 |
• | Option-based awards is the total value the named executives would have realized if they had exercised the stock options on the vesting date. |
• | Share-based awards is the payout value of the 2013 ESU awards for the named executives. See the Payout of 2013 executive share unit award section for more information. |
• | Non-equity incentive plan compensation is the short-term incentive award for 2015. This amount is shown under Annual incentive plans in the Summary compensation table on page 102. |
TCPL Annual information form 2015 | 122 |
Name | Grant date | Total number of securities under options granted (#) | Option exercise price ($) | Number of options that vested during the year (#) | Share price on vesting date ($) | Value at vesting ($) | |||||
Russell K. Girling | 25-Feb-2014 | 439,982 | 49.03 | 146,661 | 54.49 | 800,769 | |||||
15-Feb-2013 | 383,275 | 47.09 | 127,759 | 57.00 | 1,266,092 | ||||||
17-Feb-2012 | 385,475 | 41.95 | 128,492 | 57.00 | 1,933,805 | ||||||
Donald R. Marchand | 25-Feb-2014 | 155,460 | 49.03 | 51,820 | 54.49 | 282,937 | |||||
15-Feb-2013 | 123,368 | 47.09 | 41,122 | 57.00 | 407,519 | ||||||
17-Feb-2012 | 96,369 | 41.95 | 32,123 | 57.00 | 483,451 | ||||||
Alexander J. Pourbaix | 25-Feb-2014 | 252,708 | 49.03 | 84,236 | 54.49 | 459,929 | |||||
15-Feb-2013 | 220,819 | 47.09 | 73,607 | 57.00 | 729,445 | ||||||
17-Feb-2012 | 213,687 | 41.95 | 71,229 | 57.00 | 1,071,996 | ||||||
Karl Johannson | 25-Feb-2014 | 136,507 | 49.03 | 45,502 | 54.49 | 248,441 | |||||
15-Feb-2013 | 97,236 | 47.09 | 32,412 | 57.00 | 321,203 | ||||||
2-Nov-2012 | 48,450 | 45.29 | 16,150 | 44.22 | — | ||||||
17-Feb-2012 | 32,899 | 41.95 | 10,966 | 57.00 | 165,038 | ||||||
William C. Taylor | 25-Feb-2014 | 72,202 | 49.03 | 24,067 | 54.49 | 131,406 | |||||
15-Feb-2013 | 26,132 | 47.09 | 8,710 | 57.00 | 86,316 | ||||||
17-Feb-2012 | 26,071 | 41.95 | 8,690 | 57.00 | 130,785 |
TCPL Annual information form 2015 | 123 |
at December 31, 2015 Plan category | Number of securities to be issued upon exercise of outstanding options (#) | Weighted-average exercise price of outstanding options ($) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column) (#) | |||
Equity compensation plans approved by security holders | 9,819,819 | 46.62 | 6,123,649 | |||
Equity compensation plans not approved by security holders | N/A | N/A | N/A | |||
Total | 9,819,819 | 46.62 | 6,123,649 |
Dilution | Overhang | Burn rate | |||||||||
Effective date | Total number of shares outstanding (A) | Total number of options outstanding (B) | Total reserve (C) | Total options granted during year (D) | Options outstanding as a % of shares outstanding (B / A) | % of stock options outstanding plus total reserve divided by total shares outstanding ((B + C) / A) | Grant as a % of shares outstanding (D / A) | ||||
Dec 31, 2013 | 707,441,313 | 7,393,698 | 10,507,290 | 1,939,199 | 1.05 | 2.53 | 0.27 | ||||
Dec 31, 2014 | 708,662,996 | 8,464,305 | 8,215,001 | 2,292,289 | 1.19 | 2.35 | 0.32 | ||||
Dec 31, 2015 | 702,614,096 | 9,819,819 | 6,123,649 | 2,214,028 | 1.40 | 2.27 | 0.32 |
TCPL Annual information form 2015 | 124 |
at December 31, 2015 | Annual benefits | ||||||||||||
Name | Number of years of credited service | At year end ($) | At age 65 ($) | Opening present value of defined benefit obligation ($) | Compensatory change ($) | Non- compensatory change ($) | Closing present value of defined benefit obligation ($) | ||||||
Russell K. Girling | 20.00 | 885,000 | 1,398,000 | 13,610,000 | 326,000 | 330,000 | 14,266,000 | ||||||
Donald R. Marchand | 21.92 | 314,000 | 479,000 | 5,025,000 | 454,000 | 105,000 | 5,584,000 | ||||||
Alexander J. Pourbaix | 20.00 | 442,000 | 770,000 | 7,275,000 | 179,000 | 154,000 | 7,608,000 | ||||||
Karl Johannson | 20.00 | 275,000 | 419,000 | 4,780,000 | 301,000 | 166,000 | 5,247,000 | ||||||
William C. Taylor | 19.75 | 182,000 | 314,000 | 3,549,000 | 530,000 | 13,000 | 4,092,000 |
• | In 2004, the committee approved arrangements for Mr. Girling, Mr. Pourbaix, Mr. Johannson and Mr. Taylor to receive additional credited service to recognize their high potential and to retain them as employees. The credited service was received for years when they were not formally enrolled in the pension plan, but were employees of TransCanada. Messrs. Girling, Pourbaix and Johannson each received an additional three years of credited service on September 8, 2007 after maintaining continuous employment with us of the same duration. Mr. Taylor received an additional 2.08 years of credited service. The additional credited service is recognized only in the supplemental pension plan for earnings exceeding the maximum set under the Income Tax Act (Canada). |
• | Annual benefits at year end is the annual lifetime benefit payable at age 60, based on the years of credited service and the actual pensionable earnings history, as of December 31, 2015. |
• | Annual benefits at age 65 is the annual lifetime benefit payable at age 65, based on the years of credited service at age 65 and the actual pensionable earnings history, as of December 31, 2015. |
• | Opening and closing present value of defined benefit obligation is at December 31, 2014 and December 31, 2015, respectively. It represents actuarial assumptions and methods that are consistent with those used for calculating the pension obligations disclosed in our 2014 and 2015 consolidated financial statements. These assumptions reflect our best estimate of future events, and the values in the above table may not be directly comparable to similar estimates of pension obligations that may be disclosed by other corporations. |
• | Compensatory change in the present value of the obligation includes the service cost to TransCanada in 2015, plus compensation changes that were higher or lower than the base salary assumption, and plan changes. |
• | Non-compensatory change in the present value of the obligation includes the interest on the accrued obligation at the start of the year and changes in assumptions in the year. |
TCPL Annual information form 2015 | 125 |
• | a security plan that provides a safety net if there are significant medical expenses, and |
TCPL Annual information form 2015 | 126 |
Base salary | Resignation | Payments end. |
Termination without cause | Severance allowance includes a lump-sum payment of the base salary as of the separation date multiplied by the notice period. | |
Termination with cause | ||
Retirement | Payments end. | |
Death | ||
Short-term incentive | Resignation | Not paid. |
Termination without cause | Year of separation: Equals the average bonus pro-rated by the number of months in the current year prior to the separation date. | |
Years after separation: Equals the average bonus multiplied by the notice period. | ||
Termination with cause | Not paid. | |
Retirement | Year of separation: Equals the average bonus pro-rated by the number of months in the current year prior to the separation date. | |
Death | ||
ESUs | Resignation | Vested units are paid out; unvested units are forfeited. |
Termination without cause | Vested units are paid out. | |
Unvested units are forfeited, however the original grant value is generally paid out on a pro rata basis. | ||
Termination with cause | Vested units are paid out, unvested units are forfeited. | |
Retirement | Vested units are paid out. Unvested units continue to vest and the value is assessed at the end of the term. The award is pro-rated for the period of employment up to the retirement date. | |
Death | Vested units are paid out. | |
Unvested units are forfeited, however the original grant value is generally paid out on a pro rata basis. | ||
Stock options | Resignation | Grants after January 1, 2010 |
Vested stock options must be exercised by their expiry date or six months from the separation date (whichever is earlier). | ||
No stock options vest after the last day of employment. | ||
Grants before 2010 | ||
Outstanding stock options continue to vest for six months from the separation date and must be exercised by their expiry date or six months from the separation date (whichever is earlier). | ||
Termination without cause | Vested stock options must be exercised by the earlier of i) their expiry date or ii) the later of a) the end of the notice period, and b) six months following the separation date. | |
No stock options vest after the last day of the notice period. | ||
Termination with cause | Grants after January 1, 2010 | |
Vested stock options must be exercised by their expiry date or six months from the separation date (whichever is earlier). | ||
No stock options vest after the last day of employment. | ||
Grants before 2010 | ||
Outstanding stock options must be exercised by their expiry date or six months from the separation date (whichever is earlier). |
TCPL Annual information form 2015 | 127 |
Stock options (continued) | Retirement | Grants after January 1, 2012 Outstanding stock options continue to vest and must be exercised by their expiry date or three years from the separation date (whichever is earlier). If there is less than six months between the vesting date and the expiry date, the expiry date is extended for six months from the final vesting date of the options. |
Grants before 2012 Outstanding stock options vest immediately and must be exercised by their expiry date or three years from the separation date (whichever is earlier). | ||
Death | Outstanding stock options vest immediately and must be exercised by their expiry date or the first anniversary of death (whichever is earlier). | |
Pension | Resignation | |
Termination without cause | Paid as a commuted value or monthly benefit according to the Registered Plan, the Supplemental Plan, or both, as applicable. | |
Termination with cause | ||
Retirement | For termination without cause, credited service is provided for the applicable notice period. | |
Death | ||
Benefits | Resignation | Coverage ends, or retiree benefits begin if eligible. |
Termination without cause | Coverage continues during the notice period (or an equivalent lump-sum payout is made). Retiree benefits eligibility is determined at the end of the notice period. | |
Termination with cause | Coverage continues during the notice period (or an equivalent lump-sum payout is made). Once the notice period ends, coverage ends and retiree benefits begin if eligible. | |
Retirement | Coverage ends, or retiree benefits begin if eligible. | |
Death | Coverage continues to eligible dependents for a specified period of time after death. | |
Perquisites | Resignation | Payments end. |
Termination without cause | A lump-sum cash payment equal to the corporate cost of the perquisite package in the one-year period preceding the separation date multiplied by the notice period. | |
Termination with cause | ||
Retirement | Payments end. | |
Death | ||
Other | Resignation | – |
Termination without cause | Out-placement services. | |
Termination with cause | – | |
Retirement | – | |
Death | – |
• | Resignation includes voluntary resignation but not resignation as a result of constructive dismissal. If a named executive resigns because of constructive dismissal, it is treated as termination without cause. |
• | The short-term incentive award is not paid on resignation unless the Board uses its discretion. |
• | Average bonus equals the average short-term incentive award paid to the named executive for the three years preceding the separation date. |
• | The notice period is currently two years for each named executive. |
TCPL Annual information form 2015 | 128 |
TCPL Annual information form 2015 | 129 |
Without a change of control | With a change of control | ||||
Name | Termination with cause ($) | Termination without cause ($) | Retirement ($) | Death ($) | Termination without cause ($) |
Russell K. Girling | _ | 13,742,459 | 3,474,769 | 6,033,103 | 16,017,192 |
Donald R. Marchand | _ | 4,492,904 | 890,605 | 1,776,230 | 5,267,191 |
Alexander J. Pourbaix | _ | 7,772,804 | 1,580,790 | 3,047,457 | 8,459,544 |
Karl Johannson | _ | 4,976,628 | 825,419 | 1,617,085 | 5,114,293 |
William C. Taylor | _ | 3,213,769 | 611,949 | 1,092,195 | 3,664,499 |
• | Termination without cause following a change of control also applies if the named executive resigns because of constructive dismissal and the separation date is within two years of the date of a change of control. |
• | There are no incremental payments that would be made to each named executive in the event of a change of control without termination. |
• | The amounts from share-based compensation include the payouts of outstanding 2013 ESU awards for some separation events: |
• | include additional units from reinvested dividends up to and including an equivalent number of units for the final dividend that is declared as of December 31, 2015, based on $44.90, the twenty-day volume-weighted average closing price of TransCanada shares on the TSX at December 31, 2015, and |
• | include the performance multiplier of 0.54 as determined by the committee and the Board. |
• | ESUs and stock options continue to vest under the Retirement scenario provided the named executive is age 55 or over. |
• | The values provided to Mr. Taylor in U.S. dollars have been expressed here in Canadian dollars based on the Bank of Canada's average annual exchange rate for the financial year noted, namely 1.0299 for 2013, 1.1045 for 2014, and 1.2787 for 2015. |
TCPL Annual information form 2015 | 130 |
d) | employment contracts, termination and other special arrangements with senior executive officers, or other employee groups if such action is likely to have a subsequent material(1) impact on the Company or its basic human resource and compensation policies. |
(1) | For purposes of this Charter, the term “material” includes a transaction or a series of related transactions that would, using reasonable business judgment and assumptions, have a meaningful impact on the Corporation. The impact could be relative to the Corporation’s financial performance and liabilities as well as its reputation. |
TCPL Annual information form 2015 | 131 |
TCPL Annual information form 2015 | 132 |
TCPL Annual information form 2015 | 133 |
• | EBITDA |
• | EBIT |
• | Funds generated from operations |
• | Distributable cash flow |
• | Distributable cash flow per share |
• | Comparable earnings |
• | Comparable earnings per common share |
• | Comparable EBITDA |
• | Comparable EBIT |
• | Comparable distributable cash flow |
• | Comparable distributable cash flow per share |
• | a reconciliation of comparable earnings to net income attributable to common shares in the Reconciliation of Non-GAAP Measures table, and |
• | a reconciliation of funds generated from operations to net cash provided by operations, in the Net cash provided by operations table in the Financial condition section. |
• | a reconciliation of comparable distributable cash flow to net cash provided by operations in the comparable distributable cash flow table in the Financial condition section. |
Comparable measure | Original measure |
comparable earnings | net income attributable to common shares |
comparable earnings per common share | net income per common share |
comparable EBITDA | EBITDA |
comparable EBIT | segmented earnings |
comparable distributable cash flow | distributable cash flow |
• | certain fair value adjustments relating to risk management activities |
• | income tax refunds and adjustments |
• | gains or losses on sales of assets |
• | legal, contractual and bankruptcy settlements |
• | impact of regulatory or arbitration decisions relating to prior year earnings, or |
• | restructuring costs |
• | impairment of assets and investments |
TCPL Annual information form 2015 | 134 |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; and |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results or operations and cash flows of the issuer as of, and for, the periods presented in this report. |
/s/ RUSSELL K. GIRLING | |
Russell K. Girling President and Chief Executive Officer |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; and |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results or operations and cash flows of the issuer as of, and for, the periods presented in this report. |
/s/ DONALD R. MARCHAND | |
Donald R. Marchand Executive-President, Corporate Development and Chief Financial Officer |
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