Management’s discussion and analysis
April 25, 2013
This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the quarter ended March 31, 2013, and should be read with the accompanying unaudited condensed consolidated financial statements for the quarter ended March 31, 2013 which have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our December 31, 2012 audited comparative consolidated financial statements and notes and the MD&A in our 2012 Annual Report, which have been prepared in accordance with U.S. GAAP.
About this document
Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries.
Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2012 Annual Report.
All information is as of April 25, 2013 and all amounts are in Canadian dollars, unless noted otherwise.
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management’s assessment of our future plans and financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this MD&A may include information about the following, among other things:
| • | 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 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 impact and changes required as a result of regulatory outcomes |
| • | expected outcomes with respect to legal proceedings, including arbitration |
| • | expected capital expenditures and contractual obligations |
| • | expected operating and financial results |
| • | the expected impact of future commitments and contingent liabilities |
| • | expected industry, market and economic conditions. |
Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.
Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:
Assumptions
| • | inflation rates, commodity prices and capacity prices |
| • | timing of financings and hedging |
FIRST QUARTER REPORT 2013
| · | regulatory decisions and outcomes |
| • | 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. |
Risks and uncertainties
| • | 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 |
| • | performance 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 |
| • | labour, equipment and material costs |
| • | access to capital markets |
| • | interest and foreign exchange rates |
| • | technological developments |
| • | economic conditions in North America as well as globally. |
You can read more about these factors and others in reports we have filed with Canadian securities regulators and the U.S. Securities and Exchange Commission (SEC), including the MD&A in our 2012 Annual Report.
You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.
FOR MORE INFORMATION
You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).
NON-GAAP MEASURES
We use the following non-GAAP measures:
| · | comparable earnings per common share |
· | comparable EBIT comparable depreciation and amortization |
| · | comparable interest expense |
| · | comparable interest income and other |
| · | funds generated from operations. |
FIRST QUARTER REPORT 2013
These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other entities.
EBITDA and EBIT
We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is an effective measure of our performance and an effective tool for evaluating trends in each segment. It is calculated in the same way as EBITDA, less depreciation and amortization.
Funds generated from operations
Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is an effective measure of our consolidated operating cashflow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period. See Financial condition section for a reconciliation to net cash provided by operations.
Comparable measures
We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
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 | EBIT |
| comparable depreciation and amortization | depreciation and amortization |
| comparable interest expense | interest expense |
| comparable interest income and other | interest income and other |
| comparable income taxes | income tax expense/(recovery) |
Our decision not to include a specific item is subjective and made after careful consideration. These may include:
| · | certain fair value adjustments relating to risk management activities |
| · | income tax refunds and adjustments |
| · | gains or losses on sales of assets |
| · | legal and bankruptcy settlements, and |
| · | write-downs of assets and investments. |
We calculate comparable earnings by excluding the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.
FIRST QUARTER REPORT 2013
Reconciliation of non-GAAP measures
three months ended March 31 (unaudited - millions of $, except per share amounts) | 2013 | | 2012 | |
| | | | | |
| Comparable EBITDA | 1,168 | | 1,113 | |
| Comparable depreciation and amortization | (354 | ) | (344 | ) |
| Comparable EBIT | 814 | | 769 | |
| | | | | |
| Other income statement items | | | | |
| Comparable interest expense | (257 | ) | (242 | ) |
| Comparable interest income and other | 18 | | 25 | |
| Comparable income taxes | (159 | ) | (140 | ) |
| Net income attributable to non-controlling interests | (31 | ) | (35 | ) |
| Preferred share dividends | (15 | ) | (14 | ) |
| Comparable earnings | 370 | | 363 | |
| Specific items (net of tax): | | | | |
Canadian restructuring proposal - 2012 | 84 | | - | |
Risk management activities1 | (8 | ) | (11 | ) |
| Net income attributable to common shares | 446 | | 352 | |
| | | | | |
| Comparable depreciation and amortization | (354 | ) | (344 | ) |
| Specific item: | | | | |
| Canadian restructuring proposal | (13 | ) | - | |
| Depreciation and amortization | (367 | ) | (344 | ) |
| | | | | |
| Comparable interest expense | (257 | ) | (242 | ) |
| Specific item: | | | | |
Canadian restructuring proposal - 2012 | (1 | ) | - | |
| Interest expense | (258 | ) | (242 | ) |
| | | | | |
| Comparable interest income and other | 18 | | 25 | |
| Specific items: | | | | |
Canadian restructuring proposal - 2012 | 1 | | - | |
Risk management activities1 | (6 | ) | 6 | |
| Interest income and other | 13 | | 31 | |
| | | | | |
| Comparable income taxes | (159 | ) | (140 | ) |
| Specific items: | | | | |
Canadian restructuring proposal - 2012 | 42 | | - | |
Risk management activities1 | 2 | | 11 | |
| Income taxes expense | (115 | ) | (129 | ) |
| | | | | |
| Comparable earnings per common share | $0.52 | | $0.52 | |
| Specific items (net of tax): | | | | |
Canadian restructuring proposal - 2012 | 0.12 | | - | |
Risk management activities1 | (0.01 | ) | (0.02 | ) |
| Net income per common share | $0.63 | | $0.50 | |
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
| 1 | Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments. |
| 2 | Does not include depreciation and amortization from equity investments. |
| 3 | Represents our 75 per cent direct ownership interest. |
| 4 | Represents our 53.6 per cent direct ownership interest. |
| 5 | Represents our 33.3 per cent direct ownership interest of TC PipeLines, LP and our effective ownership through TC PipeLines, LP of 8.3 per cent of each of GTN and Bison, 16.7 per cent of Northern Border and an additional effective ownership of 15.4 per cent of Great Lakes. |
| 6 | Represents our 61.7 per cent ownership interest. |
| 7 | Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own. |
FIRST QUARTER REPORT 2013
NET INCOME - WHOLLY OWNED CANADIAN PIPELINES
three months ended March 31 (millions of $) | 2013 | 2012 |
| | | |
| Canadian Mainline - net income | 151 | 47 |
| Canadian Mainline - comparable earnings | 67 | 47 |
| NGTL System | 56 | 48 |
| Foothills | 4 | 5 |
OPERATING STATISTICS - WHOLLY OWNED CANADIAN PIPELINES
| three months ended March 31 | | Canadian Mainline1 | | NGTL System2 | | ANR3 |
| (unaudited) | | 2013 | | 2012 | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | | | | | | |
| Average investment base (millions of dollars) | | 5,870 | | 5,812 | | 5,824 | | 5,282 | | n/a | | n/a |
| Delivery volumes (Bcf) | | | | | | | | | | | | |
Total | | 426 | | 430 | | 994 | | 998 | | 465 | | 482 |
Average per day | | 4.7 | | 4.7 | | 11.0 | | 11.0 | | 5.2 | | 5.3 |
| 1 | Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2013 were 231 Bcf (2012 – 247 Bcf). Average per day was 2.6 Bcf (2012 – 2.7 Bcf). |
| 2 | Field receipt volumes for the NGTL System for the three months ended March 31, 2013 were 916 Bcf (2012 – 948 Bcf). Average per day was 10.2 Bcf (2012 – 10.4 Bcf). |
| 3 | Under its current rates, which are approved by the FERC, changes in average investment base do not affect results. |
CANADIAN PIPELINES
Comparable EBITDA and net income for our rate-regulated Canadian Pipelines are affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and taxes also impact comparable EBITDA and EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.
Net income for the Canadian Mainline this quarter was $104 million higher than first quarter 2012 because of the impact of the NEB’s March 27, 2013 decision on the Canadian Restructuring Proposal. Among other things, the NEB approved an ROE of 11.50 per cent on a 40 per cent deemed common equity effective for the years 2012 to 2017 compared to the last approved ROE of 8.08 per cent on a 40 per cent deemed common equity which was used to record earnings in 2012. Comparable earnings in first quarter 2013 excludes $84 million related to the 2012 impact of the NEB decision.
Net income for the NGTL System (formerly known as the Alberta System) was $8 million higher than first quarter 2012 because of a higher average investment base and termination of the annual fixed operating, maintenance and administration (OM&A) costs component included in the 2010 - 2012 Revenue Requirement which expired at the end of 2012. The NGTL System’s results this quarter reflected the last approved ROE of 9.70 per cent on deemed common equity of 40 per cent and no incentive earnings.
U.S. PIPELINES AND INTERNATIONAL
EBITDA for our U.S. operations is generally affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.
Comparable EBITDA for the U.S. and international pipelines was US$255 million this quarter, or US$15 million lower than first quarter 2012. This was the net effect of:
| · | lower revenue at Great Lakes because of lower rates and uncontracted capacity |
| higher costs at ANR relating to services provided by other pipelines |
| higher short term and interruptible revenues at Portland. |
COMPARABLE DEPRECIATION AND AMORTIZATION
Comparable depreciation and amortization was $8 million higher this quarter than in first quarter 2012 mainly because of the higher rate base on the NGTL System.
FIRST QUARTER REPORT 2013
Oil Pipelines
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
three months ended March 31 (unaudited - millions of $) | 2013 | | 2012 | |
| | | | | |
| Keystone Pipeline System | 186 | | 174 | |
| Oil Pipeline Business Development | (7 | ) | (1 | ) |
| Oil Pipelines - comparable EBITDA | 179 | | 173 | |
| Comparable depreciation and amortization | (37 | ) | (36 | ) |
| Oil Pipelines - comparable EBIT | 142 | | 137 | |
| | | | | |
| Comparable EBIT denominated as follows: | | | | |
| Canadian dollars | 47 | | 48 | |
| U.S. dollars | 94 | | 89 | |
| Foreign exchange | 1 | | - | |
| | 142 | | 137 | |
Comparable EBITDA for the Keystone Pipeline System was $12 million higher this quarter than in first quarter 2012. This increase reflected higher revenues primarily resulting from:
| · | higher contracted volumes |
| · | higher final fixed tolls on committed pipeline capacity to Cushing, Oklahoma, which came into effect in July 2012. |
Business development expenses this quarter were $6 million higher than in first quarter 2012 because of increased activity on various development projects.
FIRST QUARTER REPORT 2013
Energy
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
three months ended March 31 (unaudited - millions of $) | 2013 | | 2012 | |
| | | | | |
| Canadian Power | | | | |
Western Power1 | 79 | | 131 | |
Eastern Power1,2 | 95 | | 93 | |
Bruce Power1 | 31 | | (13 | ) |
| General, administrative and support costs | (10 | ) | (11 | ) |
Canadian Power - comparable EBITDA1 | 195 | | 200 | |
Comparable depreciation and amortization3 | (43 | ) | (40 | ) |
Canadian Power - comparable EBIT1 | 152 | | 160 | |
| | | | | |
U.S. Power (US$) | | | | |
| Northeast Power | 77 | | 46 | |
| General, administrative and support costs | (10 | ) | (10 | ) |
| U.S. Power - comparable EBITDA | 67 | | 36 | |
| Comparable depreciation and amortization | (28 | ) | (30 | ) |
| U.S. Power - comparable EBIT | 39 | | 6 | |
| Foreign exchange | 1 | | - | |
U.S. Power - comparable EBIT (Cdn$) | 40 | | 6 | |
| | | | | |
| Natural Gas Storage | | | | |
| Alberta Storage | 20 | | 15 | |
| General, administrative and support costs | (2 | ) | (2 | ) |
Natural Gas Storage - comparable EBITDA1 | 18 | | 13 | |
Comparable depreciation and amortization3 | (3 | ) | (3 | ) |
Natural Gas Storage - comparable EBIT1 | 15 | | 10 | |
| | | | | |
| Business Development comparable EBITDA and EBIT | (4 | ) | (5 | ) |
| | | | | |
Energy - comparable EBIT1 | 203 | | 171 | |
| | | | | |
| Summary | | | | |
Energy - comparable EBITDA1 | 277 | | 244 | |
Comparable depreciation and amortization3 | (74 | ) | (73 | ) |
Energy - comparable EBIT1 | 203 | | 171 | |
| 1 | Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, Portlands Energy, Bruce Power and, in 2012, CrossAlta. In December 2012, we acquired the remaining 40 per cent interest in CrossAlta, bringing our ownership interest to 100 per cent. |
| 2 | Includes Cartier phase two of Gros-Morne starting in November 2012. |
| 3 | Does not include depreciation and amortization of equity investments. |
Comparable EBITDA for Energy was $277 million this quarter, or $33 million higher than first quarter 2012. This was the net effect of:
| · | higher equity income from Bruce Power because of incremental earnings from Units 1 and 2, which were returned to service in October 2012, the recognition of a business interruption insurance recovery and a Unit 3 outage in first quarter 2012 partially offset by the extended outage of Unit 4 in first quarter 2013 |
| · | higher earnings from U.S. Power mainly because of higher realized power prices |
FIRST QUARTER REPORT 2013
| · | lower earnings from Western Power because of the Sundance A PPA force majeure and lower realized power prices. |
CANADIAN POWER
Western and Eastern Power1
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
three months ended March 31 (unaudited - millions of $) | 2013 | | 2012 | |
| | | | | |
| Revenue | | | | |
| Western power | 142 | | 224 | |
Eastern power1 | 109 | | 103 | |
Other2 | 31 | | 25 | |
| | 282 | | 352 | |
| | | | | |
Income from equity investments3 | 22 | | 23 | |
| | | | | |
| Commodity purchases resold | | | | |
| Western power | (65 | ) | (94 | ) |
Other4 | (2 | ) | (2 | ) |
| | (67 | ) | (96 | ) |
| Plant operating costs and other | (63 | ) | (55 | ) |
| General, administrative and support costs | (10 | ) | (11 | ) |
| Comparable EBITDA | 164 | | 213 | |
Comparable depreciation and amortization5 | (43 | ) | (40 | ) |
| Comparable EBIT | 121 | | 173 | |
| 1 | Includes Cartier phase two of Gros-Morne starting in November 2012. |
| 2 | Includes sale of excess natural gas purchased for generation and sales of thermal carbon black. |
| 3 | Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy. |
| 4 | Includes the cost of excess natural gas not used in operations. |
| 5 | Does not include depreciation and amortization of equity investments. |
FIRST QUARTER REPORT 2013
Sales volumes and plant availability
Includes our share of volumes from our equity investments.
three months ended March 31 (unaudited) | 2013 | 2012 |
| | | |
| Sales volumes (GWh) | | |
| Supply | | |
Generation | | |
Western Power | 670 | 671 |
Eastern Power1 | 1,346 | 1,143 |
Purchased | | |
Sundance A & B and Sheerness PPAs2 | 1,707 | 2,039 |
Other purchases | - | 45 |
| | 3,723 | 3,898 |
| Sales | | |
Contracted | | |
Western Power | 1,707 | 2,295 |
Eastern Power1 | 1,346 | 1,143 |
Spot | | |
Western Power | 670 | 460 |
| | 3,723 | 3,898 |
Plant availability3 | | |
Western Power4 | 97% | 99% |
Eastern Power1,5 | 96% | 93% |
| 1 | Includes Cartier phase two of Gros-Morne starting in November 2012. |
| 2 | Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership. No volumes were delivered under the Sundance A PPA in 2012 and 2013. |
| 3 | The percentage of time the plant was available to generate power, regardless of whether it was running. |
| 4 | Does not include facilities that provide power to TransCanada under PPAs. |
| 5 | Does not include Bécancour because power generation has been suspended since 2008. |
Western Power’s comparable EBITDA was $79 million this quarter, or $52 million lower than first quarter 2012. Revenue also decreased by $82 million this quarter to $142 million. These decreases were mainly due to:
| · | the Sundance A PPA force majeure |
| · | lower realized power prices and |
| · | lower purchased PPA volumes during periods of lower spot prices. |
| In first quarter 2012, we recorded revenues and costs related to the Sundance A PPA as though the outages of Units 1 and 2 were interruptions of supply in accordance with the terms of the PPA. In July 2012, we received the Sundance A PPA arbitration decision which determined the units were in force majeure in first quarter 2012. In response, we recorded a charge of $30 million in second quarter 2012 equivalent to the pre-tax income we had recorded in first quarter 2012. Because the plant continues to be in force majeure, we will not record further revenues and costs until the units are returned to service. See Energy - Significant Events in the MD&A in our 2012 Annual Report for more information about the Sundance A PPA arbitration decision. |
| Average spot market power prices in Alberta were $64 per MWh this quarter, compared to $60 per MWh in first quarter 2012. This increase was mainly the result of high spot market prices in the month of March driven by plant outages and increased demand. Western Power’s average realized power price this quarter was lower than first quarter 2012 because of contracting activities. Purchased volumes were lower than first quarter 2012 mainly because of lower utilization of the Sheerness and Sundance B PPAs and higher Sundance B plant outage days. |
| Western Power’s commodity purchases resold were $65 million this quarter, or $29 million lower than first quarter 2012, because of the Sundance A PPA force majeure and lower purchased volumes during periods of lower spot prices. |
FIRST QUARTER REPORT 2013
| Eastern Power’s comparable EBITDA of $95 million was $2 million higher than first quarter 2012 because of the start up of phase two of Cartier Gros-Morne in November 2012, partially offset by lower contractual earnings at Bécancour. |
Plant operating costs and other, which includes natural gas fuel consumed in power generation, were $63 million this quarter, or $8 million higher than first quarter 2012, mainly due to higher natural gas fuel prices in 2013.
Approximately 72 per cent of Western Power sales volumes were sold under contract this quarter, compared to 83 per cent in first quarter 2012. To reduce exposure to spot market prices in Alberta, Western Power has entered into fixed-price power sales contracts to sell approximately 5,300 GWh for the remainder of 2013 and approximately 5,200 GWh in 2014.
BRUCE POWER
Our proportionate share
three months ended March 31 (unaudited - millions of $ unless noted otherwise) | 2013 | 2012 | |
| | | | |
Income/(loss) from equity investments1 | | | |
| Bruce A | 36 | (33 | ) |
| Bruce B | (5) | 20 | |
| | 31 | (13 | ) |
| | | | |
| Comprised of: | | | |
Revenues | 287 | 162 | |
Operating expenses | (173) | (135 | ) |
Depreciation and other | (83) | (40 | ) |
| | 31 | (13 | ) |
| | | | |
| Bruce Power - Other information | | | |
Plant availability2 | | | |
Bruce A3 | 66% | 48% | |
Bruce B | 78% | 86% | |
Combined Bruce Power | 72% | 62% | |
| Planned outage days | | | |
Bruce A | 90 | 91 | |
Bruce B | 70 | 46 | |
| Unplanned outage days | | | |
Bruce A | 8 | - | |
Bruce B | 9 | 4 | |
Sales volumes (GWh)1 | | | |
Bruce A3 | 2,097 | 747 | |
Bruce B | 1,735 | 1,909 | |
| | 3,832 | 2,656 | |
| | | | |
| Realized sales price per MWh | | | |
Bruce A | $68 | $66 | |
Bruce B4 | $53 | $54 | |
Combined Bruce Power | $59 | $57 | |
| 1 | Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. |
| 2 | The percentage of time the plant was available to generate power, regardless of whether it was running. |
| 3 | Plant availability and sales volumes for 2013 include the incremental impact of Units 1 and 2 which were returned to service in October 2012. |
| 4 | Includes revenues under the floor price mechanism, revenues from contract settlements and volumes and revenues associated with deemed generation. |
FIRST QUARTER REPORT 2013
Equity income from Bruce A increased by $69 million this quarter, compared to first quarter 2012. The increase was due to:
| · | incremental earnings from Units 1 and 2 which returned to service in October 2012 |
| · | recognition of an insurance recovery of approximately $40 million related to the May 2012 Unit 2 electrical generator failure and the impact the event had on Bruce A in 2012 and 2013 |
| · | higher earnings from Unit 3 due to the West Shift Plus planned outage during first quarter 2012. |
These increases were partially offset by the impact of the Unit 4 planned outage which began in August 2012 and was completed April 13, 2013.
The availability percentage for Units 1 and 2 increased through first quarter 2013 with an average availability in the mid 80s. These units are now able to operate at full power; however, as Units 1 and 2 have not operated for an extended period of time they may experience slightly higher forced outage rates and reduced availability percentages in 2013.
Equity loss from Bruce B was $5 million this quarter, compared to equity income of $20 million in first quarter 2012. The decrease was mainly due to lower volumes and higher operating costs resulting from higher planned outage days.
Under the contract with the Ontario Power Authority (OPA), all of the output from Bruce A is sold at a fixed price per MWh, adjusted annually for inflation on April 1. Bruce A also recovers fuel costs from the OPA.
| Bruce A Fixed price | Per MWh |
| | |
| April 1, 2013 - March 31, 2014 | $69.19 |
| April 1, 2012 - March 31, 2013 | $68.23 |
| April 1, 2011 - March 31, 2012 | $66.33 |
Under the same contract, all output from Bruce B is subject to a floor price adjusted annually for inflation on April 1.
| Bruce B Floor price | Per MWh |
| | |
| April 1, 2013 - March 31, 2014 | $52.34 |
| April 1, 2012 - March 31, 2013 | $51.62 |
| April 1, 2011 - March 31, 2012 | $50.18 |
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. We currently expect 2013 spot prices to be less than the floor price for the year and therefore no amounts recorded in revenues in first quarter 2013 are expected to be repaid.
Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.
The overall plant availability percentage in 2013 is expected to be in the mid 80s for Bruce A and the high 80s for Bruce B. Planned maintenance on two of the Bruce B units and one of the Bruce A units is expected to be completed in second quarter 2013.
FIRST QUARTER REPORT 2013
U.S. POWER
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
three months ended March 31 (unaudited - millions of US $) | 2013 | | 2012 | |
| | | | | |
| Revenue | | | | |
Power1 | 433 | | 195 | |
Capacity | 47 | | 40 | |
Other2 | 29 | | 19 | |
| | 509 | | 254 | |
| Commodity purchases resold | (306 | ) | (117 | ) |
Plant operating costs and other2 | (126 | ) | (91 | ) |
| General, administrative and support costs | (10 | ) | (10 | ) |
| Comparable EBITDA | 67 | | 36 | |
| Comparable depreciation and amortization | (28 | ) | (30 | ) |
| Comparable EBIT | 39 | | 6 | |
| 1 | The realized gains and losses from financial derivatives used to buy and sell power, natural gas and fuel oil to manage U.S. Power’s assets are presented on a net basis in power revenues. |
| 2 | Includes revenues and costs related to a third party service agreement at Ravenswood, the activity level of which increased in 2013. |
Sales volumes and plant availability
three months ended March 31 (unaudited) | 2013 | 2012 |
| | | |
| Physical sales volumes (GWh) | | |
| Supply | | |
Generation | 1,051 | 1,154 |
Purchased | 2,479 | 1,570 |
| | 3,530 | 2,724 |
| | | |
Plant availability1 | 79% | 80% |
| 1 | The percentage of time the plant was available to generate power, regardless of whether it is running. |
U.S. Power’s comparable EBITDA was US$67 million this quarter, or US$31 million higher than first quarter 2012. This was the net effect of:
| · | higher realized power prices |
| · | higher realized capacity prices in New York |
| · | higher revenues on sales to wholesale, commercial and industrial customers |
| · | higher operating costs due to higher fuel prices. |
Commodity prices in both New York and New England were significantly higher this quarter than first quarter 2012. The combination of higher natural gas prices, pipeline constraints and an increase in demand for natural gas resulted in higher spot power prices this quarter.
Physical sales volumes this quarter were higher than the same period in 2012 due to higher purchased volumes to serve increased sales to wholesale, commercial and industrial customers in the New England and PJM markets. Generation volumes were lower, mainly due to lower generation in New England partly offset by higher Ravenswood generation.
Power revenue was US$433 million this quarter, or US$238 million higher than first quarter 2012. This was mainly because of the combination of higher realized power prices and higher sales volumes to wholesale, commercial and industrial customers.
FIRST QUARTER REPORT 2013
Capacity revenue was US$47 million this quarter, or US$7 million higher than first quarter 2012. A two per cent increase in New York Zone J spot capacity prices and the impact of hedging activities resulted in higher realized prices in New York, partially offset by lower capacity prices in New England.
Commodity purchases resold were US$306 million this quarter, or US$189 million higher than first quarter 2012 because we purchased higher volumes of power at higher prices to fulfill increased power sales commitments to wholesale, commercial and industrial customers.
Plant operating costs and other, which includes fuel gas consumed in generation, was US$126 million this quarter, or US$35 million higher than first quarter 2012 because of higher natural gas fuel prices.
As at March 31, 2013, approximately 2,600 GWh or 41 per cent of U.S. Power’s planned generation is contracted for 2013, and 2,400 GWh or 27 per cent for 2014. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.
NATURAL GAS STORAGE
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
three months ended March 31 (unaudited - millions of $) | 2013 | | 2012 | |
| | | | | |
| Alberta Storage | 20 | | 15 | |
| General, administrative and support costs | (2 | ) | (2 | ) |
| Comparable EBITDA | 18 | | 13 | |
| Comparable depreciation and amortization | (3 | ) | (3 | ) |
| Comparable EBIT | 15 | | 10 | |
Comparable EBITDA was $18 million this quarter, or $5 million higher than first quarter 2012, mainly due to higher earnings from CrossAlta resulting from the acquisition of the remaining 40 per cent interest in December 2012. The seasonal nature of natural gas storage generally results in higher revenues in the winter season.
FIRST QUARTER REPORT 2013
Recent developments
NATURAL GAS PIPELINES
NEB decision on the Canadian Restructuring Proposal
| On March 27, 2013, the NEB issued its decision on our application to change the business structure and the terms and conditions of service for the Canadian Mainline, including tolls for 2012 and 2013. |
The NEB approved several of our proposed changes, including the Canadian Mainline’s revenue requirement for 2011 and 2012. At the same time, the NEB agreed with us that the Canadian Mainline has been significantly affected by market forces with the result that throughput has decreased significantly, and as a result, the Canadian Mainline tolls have increased over a short period of time eroding the Canadian Mainline’s competitiveness. The response of the NEB was to adopt a multi-year fixed tolls approach which it believes will provide shippers with greater toll certainty and stability. Under the decision, long-term firm tolls are fixed through 2017 (subject to being re-opened under certain circumstances) at what the NEB determined is a competitive level. Although long-term firm tolls are fixed, the Canadian Mainline has been given pricing discretion for interruptible and short-term firm services. The NEB concluded in the decision that this framework will provide us with reasonable opportunity to recover our costs, over a reasonable period of time. Under or over collection variances to the revenue requirement inclusive of the return on and of capital will be carried over in deferral accounts to be dealt with in future NEB proceedings in 2017 (or earlier under certain circumstances). At that time, the NEB will determine how any variances contained in the deferral accounts will be addressed and the extent of cost disallowances, if any. As a result of the multi-year fixed tolls and increased risk associated with fluctuations in cash flow, the NEB increased the allowed return to 11.50 per cent on a 40 per cent equity ratio.
The decision significantly alters the regulatory framework that has formed the basis for more than $10 billion of regulated pipeline investment over the last sixty years. We have determined that we will seek regulatory and potentially legal review and variance of certain aspects of the decision.
NGTL System
The Alberta System is now known as the NGTL System to better reflect the service provided and continued growth in British Columbia.
Our application to contract for capacity on the Canadian Mainline and Foothills Pipelines was denied as part of the NEB’s decision regarding the Canadian Restructuring Proposal. Therefore, the location of our export delivery will remain at Empress and the Alberta/BC border.
NGTL System expansion projects
We have been continuing our expansion of the NGTL System and have placed approximately $340 million of new facilities into service to date in 2013. We have applied and received approval from the NEB for an additional $300 million of new facilities with in-service dates planned for later in 2013. The NEB has also recommended approval for the Chinchaga lateral, an approximate $100 million project, that is planned to be placed in service in early 2014. To date in 2013, we have applied for an additional $60 million of facilities and are planning regulatory applications for further expansion into B.C. which we estimate will cost between $1.0 billion and $1.5 billion to accommodate the Prince Rupert Gas Transmission Project.
Prince Rupert Gas Transmission Project
We signed the project development agreement for the Prince Rupert Gas Transmission Project with Progress Energy Canada Ltd. in February 2013 and are now working to initiate the environmental assessment process, including developing and filing the project description that we plan to submit to the B.C. Environmental Assessment Office and the Canadian Environmental Assessment Agency (CEAA) in second quarter 2013.
Coastal GasLink Pipeline Project
We are currently focused on community, landowner, government and First Nations engagement as the Coastal GasLink pipeline project advances through the regulatory process with the B.C. Environmental Assessment Office and the CEAA. We expect to begin an NGTL open season to provide delivery service to Vanderhoof, B.C. on Coastal GasLink in second quarter 2013.
FIRST QUARTER REPORT 2013
Portland
We are holding a 45-day binding open season from April to May 2013 to determine the demand for new natural gas supply options for the New England and Atlantic Canada markets. The results could support an increase in our capacity from 168 MMcf/d to between 300 MMcf/d and 350 MMcf/d. The project will require upstream expansion on the Canadian Mainline that will be subject to an assessment of the implications of the recent NEB decision on the Canadian Restructuring Proposal.
Tamazunchale
A variety of construction activities are underway on the Tamazunchale Extension and the project remains on schedule to meet the planned in-service date of first quarter 2014.
OIL PIPELINES
Gulf Coast Project
We are constructing a 36-inch pipeline from Cushing, Oklahoma to the U.S. Gulf Coast and expect to begin delivering crude oil to Port Arthur, Texas at the end of 2013. Construction is approximately 70 per cent complete and we estimate the total cost of the Cushing to Port Arthur facilities to be US$2.3 billion.
Construction of the 76 km (47 mile) Houston Lateral pipeline to transport crude oil to Houston refineries is expected to begin in mid 2013 and be complete by mid 2014 at a total cost of approximately US$300 million.
The Gulf Coast Project will have an initial capacity of up to 700,000 barrels per day.
Keystone XL Pipeline
In January 2013, the Governor of Nebraska approved our proposed re-route after the Nebraska Department of Environmental Quality issued its final evaluation report noting that construction and operation of Keystone XL is expected to have minimal environmental impacts in Nebraska.
On March 1, 2013, the U.S. Department of State (DOS) released its Draft Supplemental Environmental Impact Statement for the Keystone XL Pipeline. The impact statement reaffirmed that construction of the proposed pipeline from the U.S./Canada border in Montana to Steele City, Nebraska would not result in any significant impact to the environment. The DOS is in the process of reviewing comments on the impact statement that it received during a public comment period that ended on April 22, 2013. Once the DOS has completed its review, it is anticipated it will issue a Final Supplemental Environmental Impact Statement and then consult with other governmental agencies during a National Interest Determination period of up to 90 days, before making a decision on our Presidential Permit application.
Due to ongoing delays in the issuance of a Presidential Permit for Keystone XL, we now expect the pipeline to be in service in the second half of 2015 and, based on our pipeline construction experience, the US$5.3 billion cost estimate will increase depending on the timing of the permit. As of March 31, 2013, we had invested $1.8 billion in the project.
Energy East Pipeline
We announced in April 2013 that we are 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, which follows a successful expression of interest phase and discussions with prospective shippers, began in April 2013 and closes in June 2013.
The Energy East Pipeline project involves converting natural gas pipeline capacity in approximately 3,000 kilometres of our existing Canadian Mainline to crude oil service and constructing up to approximately 1,400 kilometres of new pipeline. Subject to the results of the open season, the project will have the capacity to transport as much as 850,000 barrels of crude oil per day, increasing access to eastern Canadian markets.
We have begun Aboriginal and stakeholder engagement and field work as part of our initial design and planning. If the open season is successful, we will apply for regulatory approval to build and operate the facilities, with a potential in-service date of late 2017.
Northern Courier Pipeline
The Fort Hills Energy Limited Partnership has not indicated that their recent decision to cancel the Voyageur upgrader project has changed their current plans for Northern Courier. We have nearly completed the field
FIRST QUARTER REPORT 2013
work and Aboriginal and stakeholder engagement necessary to allow us to file the permit application with the Energy Resources Conservation Board and expect to file the application in second quarter 2013.
ENERGY
Ontario Solar
In late 2011, we agreed to buy nine Ontario solar projects (combined capacity of 86 MW) from Canadian Solar Solutions Inc. We expect to close the acquisition of the first three projects (combined capacity of 29 MW) by mid 2013 for a total cost of approximately $175 million. We expect to acquire the remaining six projects later in 2013 and 2014, subject to regulatory approvals.
Bruce Power returned Unit 4 to service on April 13, 2013 after completing an expanded life extension outage investment program which began in August 2012. It is anticipated that this investment will allow Unit 4 to operate until at least 2021.
On April 5, 2013, Bruce Power announced that it had reached an agreement with the OPA 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.
FIRST QUARTER REPORT 2013
Other income statement items
three months ended March 31 (unaudited - millions of $) | 2013 | 2012 | |
| | | | |
| Comparable interest expense | 257 | 242 | |
| Comparable interest income and other | (18 | ) (25 | ) |
| Comparable income taxes | 159 | 140 | |
| Net income attributable to non-controlling interests | 31 | 35 | |
three months ended March 31 (unaudited - millions of $) | 2013 | | 2012 | |
| | | | | |
Comparable interest on long-term debt (including interest on junior subordinated notes) | | | | |
| Canadian dollar-denominated | 122 | | 128 | |
| U.S. dollar-denominated | 188 | | 186 | |
| Foreign exchange | 1 | | - | |
| | 311 | | 314 | |
| | | | | |
| Other interest and amortization expense | 1 | | 2 | |
| Capitalized interest | (55 | ) | (74 | ) |
| Comparable interest expense | 257 | | 242 | |
Comparable interest expense this quarter was $15 million higher than first quarter 2012 because of the following:
| · | lower capitalized interest as a result of placing the refurbished units at Bruce Power in service, partially offset by increased capitalized interest for the Gulf Coast Project |
| · | lower interest expense due to Canadian and U.S. dollar-denominated debt maturities, partially offset by debt issues of US$750 million in January 2013, US$1 billion in August 2012 and US$500 million in March 2012. |
Comparable interest income and other this quarter was $7 million lower than first quarter 2012 because we had realized losses in 2013 compared to realized gains in 2012 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.
Comparable income taxes were $159 million this quarter compared to $140 million in first quarter 2012. The increase was mainly the result of higher pre-tax earnings in 2013 compared to 2012 and changes in the proportion of income earned between Canadian and foreign jurisdictions.
FIRST QUARTER REPORT 2013
We strive to maintain financial strength and flexibility in all parts of an economic cycle, and rely on our operating cash flows to sustain our business, pay dividends and fund a portion of our growth.
We access capital markets to meet our financing needs, manage our capital structure and preserve our credit ratings.
We believe we have the capacity to fund our existing capital program through predictable cash flow from our operations, access to capital markets, cash on hand and substantial committed credit facilities.
CASH FROM OPERATING ACTIVITIES
three months ended March 31 (unaudited - millions of $) | 2013 | | 2012 | |
| | | | | |
Funds generated from operations1 | 916 | | 871 | |
| Increase in operating working capital | (210 | ) | (169 | ) |
| Net cash from operations | 706 | | 702 | |
| 1 | See the non-GAAP measures section in this MD&A for further discussion of funds generated from operations. |
Net cash provided by operations this quarter was $4 million higher than first quarter 2012, mainly because of an increase in funds generated from our operations which is consistent with our increase in earnings, partly offset by changes in operating working capital.
Our current assets were $2.5 billion and current liabilities were $5.5 billion, leaving us with a working capital deficit of $3.0 billion at March 31, 2013 compared to $3.1 billion at the end of 2012. This working capital deficiency is considered to be in the normal course of business and any funding of working capital is managed through our ability to generate cash flow and our ongoing access to capital markets.
CASH USED IN INVESTING ACTIVITIES
three months ended March 31 (unaudited - millions of $) | 2013 | 2012 |
| | | |
| Capital expenditures | | 929 | | 464 |
| Equity investments | | 32 | | 216 |
Our capital expenditures this quarter were primarily related to the Gulf Coast Project and expansion of the NGTL System.
CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES
three months ended March 31 (unaudited - millions of $) | 2013 | 2012 | |
| | | | |
| Long-term debt issued, net of issue costs | | 734 | | 492 | |
| Long-term debt repaid | | (14 | ) | (548 | ) |
| Notes payable repaid | | (829 | ) | (46 | ) |
| Dividends and distributions paid | | (350 | ) | (343 | ) |
| Equity financing activities | | 618 | | 14 | |
In January 2013, we issued US$750 million of senior notes, maturing on January 15, 2016 and bearing interest at 0.75 per cent. These notes were issued under the US$4.0 billion debt shelf prospectus filed in November 2011.
In March 2013, we completed a public offering of 24 million Series 7 cumulative redeemable first preferred shares at a price of $25 per share for aggregate gross proceeds of $600 million. Investors will be entitled to
FIRST QUARTER REPORT 2013
receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly. Investors will have the right to convert their shares into cumulative redeemable first preferred shares, Series 8, every fifth year beginning on April 30, 2019. The holders of Series 8 will be entitled to receive quarterly floating rate cumulative dividends at an annualized rate equal to the then 90-day Government of Canada treasury bill rate plus 2.38 per cent.
The net proceeds of the two offerings will be used to fund our capital program, for general corporate purposes and to reduce short term indebtedness.
DIVIDENDS
On April 25, 2013 we declared quarterly dividends as follows:
| Quarterly dividend on our common shares |
| |
| $0.46 per share (for the quarter ending June 30, 2013) |
| Payable on July 31, 2013 to shareholders of record at the close of business on June 28, 2013 |
| |
| Quarterly dividends on our preferred shares |
| |
Series 1 $0.2875 (for the quarter ending June 30, 2013) |
Series 3 $0.25 (for the quarter ending June 30, 2013) |
| Payable on July 2, 2013 to shareholders of record at the close of business on May 31, 2013 |
Series 5 $0.275 (for the three month period ending July 30, 2013) |
Series 7 $0.25 (for the three month period ending July 30, 2013) |
| Payable on July 30, 2013 to shareholders of record at the close of business on June 28, 2013 |
| as at April 22, 2013 | | |
Common shares | Issued and outstanding 707 million | |
Preferred shares | Issued and outstanding | Convertible to |
| Series 1 | 22 million | 22 million Series 2 preferred shares |
| Series 3 | 14 million | 14 million Series 4 preferred shares |
| Series 5 | 14 million | 14 million Series 6 preferred shares |
| Series 7 | 24 million | 24 million Series 8 preferred shares |
| Options to buy common shares | Outstanding 8 million | Exercisable 5 million |
FIRST QUARTER REPORT 2013
CREDIT FACILITIES
We use committed, revolving credit facilities to support our commercial paper programs, along with additional demand facilities, for general corporate purposes including issuing letters of credit and providing additional liquidity.
At March 31, 2013, we had $5 billion in unsecured credit facilities, including:
| Amount | Unused capacity | Subsidiary | For | Matures |
| | | | | |
| $2.0 billion | $2.0 billion | TransCanada PipeLines Limited (TCPL) | Committed, revolving, extendible credit facility that supports TCPL’s Canadian commercial paper program | October 2017 |
| US$1.0 billion | US$1.0 billion | TransCanada PipeLine USA Ltd. (TCPL USA) | Committed, revolving extendible credit facility that supports a TCPL USA U.S. dollar commercial paper program in the U.S. | October 2013 |
| US$1.0 billion | US$1.0 billion | TransCanada Keystone Pipeline, LP | Committed, revolving, extendible credit facility that supports a U.S. dollar commercial paper program in Canada dedicated to funding a portion of Keystone | November 2013 |
$0.9 billion, US$0.1 billion | $360 million | TCPL, TCPL USA | Demand lines for issuing letters of credit and as a source of additional liquidity. At March 31, 2013, we had outstanding $640 million in letters of credit under these lines | Demand |
See Risks and financial instruments for more information about liquidity, market and other risks.
CONTRACTUAL OBLIGATIONS
Other than a decrease of $560 million to our capital commitments and $190 million to other purchase commitments, there were no material changes to our contractual obligations in first quarter 2013 or to payments due in the next five years or after. See the MD&A in our 2012 Annual Report for more information about our contractual obligations.
FIRST QUARTER REPORT 2013
Financial risks and financial instruments
We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and ultimately shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.
We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and ultimately shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.
Please see our 2012 Annual Report for more information about the risks we face in our business. In addition to those disclosed risks, in the NEB’s March 2013 decision on our Canadian Restructuring Proposal, the NEB found that the fundamental business risk facing the Canadian Mainline has increased. The tolling framework created by the NEB decision results in higher variability in cash flows and greater uncertainty about the ultimate recovery of the Canadian Mainline’s cost of service. Otherwise, our risks have not changed substantially since December 31, 2012.
We manage our liquidity by continuously forecasting our cash flow for a 12 month period and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.
COUNTERPARTY CREDIT RISK
We have exposure to counterparty credit risk in the following areas:
| · | the fair value of derivative assets |
| · | notes, loans and advances receivable. |
We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 2013, we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration of $256 million with one counterparty at March 31, 2013 (December 31, 2012 - $259 million). This amount is secured by a guarantee from the counterparty’s parent company and we anticipate collecting the full amount.
We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.
FOREIGN EXCHANGE RISK
Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. operations continue to grow, our exposure to changes in currency rates increases. Some of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.
We use foreign exchange derivatives to manage other foreign exchange transactions, including foreign exchange exposures that arise on some of our regulated assets. We defer some of the realized gains and losses on these derivatives as regulatory assets and liabilities until we recover or pay them to shippers according to the terms of the shipping agreements.
AVERAGE EXCHANGE RATE - U.S. TO CANADIAN DOLLARS
| First quarter 2013 | 1.01 |
| First quarter 2012 | 1.00 |
The impact of changes in the value of the U.S. dollar on our U.S. operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below. Comparable EBIT is a non-GAAP measure.
FIRST QUARTER REPORT 2013
SIGNIFICANT U.S. DOLLAR-DENOMINATED AMOUNTS
three months ended March 31 (unaudited - millions of US$) | 2013 | 2012 | |
| | | | |
| U.S. and International Natural Gas Pipelines comparable EBIT | | 200 | | 215 | |
| U.S. Oil Pipelines comparable EBIT | | 94 | | 89 | |
| U.S. Power comparable EBIT | | 39 | | 6 | |
| Interest expense on U.S. dollar-denominated long-term debt | | (188 | ) | (186 | ) |
| Capitalized interest on U.S. capital expenditures | | 44 | | 26 | |
| U.S. non-controlling interests and other | | (48 | ) | (51 | ) |
| | | 141 | | 99 | |
NET INVESTMENT IN FOREIGN OPERATIONS
We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:
| | March 31, 2013 | | December 31, 2012 |
Asset/(liability) (unaudited - millions of $) | Fair value1 | Notional amount | | Fair value1 | Notional amount |
| | | | | | |
| U.S. dollar cross-currency swaps | | | | | |
(maturing 2013 to 2019)2 | | 5 | US 3,800 | | 82 | US 3,800 |
| U.S. dollar forward foreign exchange contracts | | | | | | |
| (maturing 2013) | | (1) | US 850 | | - | US 250 |
| | | 4 | US 4,650 | | 82 | US 4,050 |
| 1 | Fair values equal carrying values. |
| 2 | Net income in first quarter 2013 included net realized gains of $7 million (2012 - gains of $7 million) related to the interest component of cross-currency swap settlements. |
U.S. DOLLAR-DENOMINATED DEBT DESIGNATED AS A NET INVESTMENT HEDGE
| (unaudited - billions of $) | March 31, 2013 | December 31, 2012 |
| | | |
| Carrying value | 12.1 (US 11.9) | 11.1 (US 11.2) |
| Fair value | 15.0 (US 14.7) | 14.3 (US 14.4) |
FAIR VALUE OF DERIVATIVES USED TO HEDGE OUR
U.S. DOLLAR INVESTMENT IN FOREIGN OPERATIONS
The classification of the fair value of derivatives to hedge our net investments on the balance sheet.
| (unaudited - millions of $) | March 31, 2013 | December 31, 2012 | |
| | | | |
| Other current assets | 47 | 71 | |
| Intangible and other assets | 22 | 47 | |
| Accounts payable and other | 10 | 6 | |
| Other long-term liabilities | 55 | 30 | |
FIRST QUARTER REPORT 2013
NON-DERIVATIVE FINANCIAL INSTRUMENTS SUMMARY
| | March 31, 2013 | December 31, 2012 |
| (unaudited - millions of $) | Carrying amount1 | Fair value2 | Carrying amount1 | Fair value2 |
| | | | | |
| Financial assets | | | | |
| Cash and cash equivalents | 443 | 443 | 551 | 551 |
Accounts receivable and other3 | 1,269 | 1,322 | 1,288 | 1,337 |
Available for sale assets3 | 49 | 49 | 44 | 44 |
| | 1,761 | 1,814 | 1,883 | 1,932 |
| | | | | |
Financial liabilities4 | | | | |
| Notes payable | 1,474 | 1,474 | 2,275 | 2,275 |
Accounts payable and other long-term liabilities5 | 1,034 | 1,034 | 1,535 | 1,535 |
| Accrued interest | 352 | 352 | 368 | 368 |
| Long-term debt | 19,926 | 25,081 | 18,913 | 24,573 |
| Junior subordinated notes | 1,015 | 1,083 | 994 | 1,054 |
| | 23,801 | 29,024 | 24,085 | 29,805 |
| 1 | Recorded at amortized cost, except for US$350 million (December 31, 2012 - US$350 million) of long-term debt that is attributed to hedged risk which is recorded at fair value. This debt which is recorded at fair value on a recurring basis is classified in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers. |
| 2 | The fair value measurement of financial assets and liabilities recorded at amortized cost for which fair value is not equal to the carrying value would be included in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers. |
| 3 | At March 31, 2013, financial assets of $1.0 billion (December 31, 2012 - $1.1 billion) are included in accounts receivable, $70 million (December 31, 2012 - $40 million) in other current assets and $217 million (December 31, 2012 - $240 million) in intangible and other assets. |
| 4 | Condensed consolidated statement of income in first quarter 2013 included losses of $10 million (2012 - losses of $15 million) for fair value adjustments related to interest rate swap agreements on US$350 million of long-term debt at March 31, 2013 (December 31, 2012 - US$350 million). There were no other unrealized gains or losses from fair value adjustments to non-derivative financial instruments. |
| 5 | At March 31, 2013, financial liabilities of $1.0 billion (December 31, 2012 - $1.5 billion) are included in accounts payable, and $41 million (December 31, 2012 - $38 million) in other long-term liabilities. |
FIRST QUARTER REPORT 2013
DERIVATIVE INSTRUMENTS SUMMARY
The following summary does not include hedges of our net investment in foreign operations.
2013 (unaudited - millions of $ unless noted otherwise) | Power | | Natural gas | | Foreign exchange | | Interest |
| | | | | | | | |
Derivative instruments held for trading1 | | | | | | | |
Fair values2 | | | | | | |
Assets | $159 | | $85 | | $- | | $13 |
Liabilities | $(206 | ) | $(93 | ) | $(8 | ) | $(13) |
| Notional values | | | | | | | |
Volumes3 | | | | | | | |
Sales | 36,445 | | 71 | | - | | - |
Purchases | 34,536 | | 102 | | - | | - |
Canadian dollars | - | | - | | - | | 620 |
U.S. dollars | - | | - | | US 1,396 | | US 200 |
Net unrealized (losses)/gains in the three months ended March 31, 20134 | $(8 | ) | $9 | | $(6 | ) | $- |
Net realized losses in the three months ended March 31, 20134 | $(7 | ) | $(2 | ) | $(1 | ) | $- |
| Maturity dates | 2013-2017 | | 2013-2016 | | 2013-2014 | | 2013-2016 |
| | | | | | | | |
Derivative instruments in hedging relationships5,6 | | | | | | | |
Fair values2 | | | | | | | |
Assets | $70 | | $- | | $- | | $10 |
Liabilities | $(73 | ) | $(1 | ) | $(36 | ) | $- |
| Notional values | | | | | | | |
Volumes3 | | | | | | | |
Sales | 6,358 | | - | | - | | - |
Purchases | 14,400 | | 1 | | - | | - |
U.S. dollars | - | | - | | US 23 | | US 350 |
Cross-currency | - | | - | | 136/US 100 | | - |
Net realized gains in the three months ended March 31, 20134 | $73 | | $- | | $- | | $2 |
| Maturity dates | 2013-2018 | | 2013 | | 2013-2014 | | 2013-2015 |
| 1 | All derivative instruments held for trading have been entered into for risk management purposes and are subject to our risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage our exposure to market risk. |
| 2 | Fair values equal carrying values. |
| 3 | Volumes for power and natural gas derivatives are in GWh and Bcf, respectively. |
| 4 | Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in interest expense and interest income and other, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles. |
| 5 | All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $10 million and a notional amount of US$350 million. For the three months ended March 31, 2013, net realized gains on fair value hedges were $2 million and were included in interest expense. For the three months ended March 31, 2013, we did not record any amounts in net income related to ineffectiveness for fair value hedges. |
| 6 | For the three months ended March 31, 2013, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur. |
FIRST QUARTER REPORT 2013
The following summary does not include hedges of our net investment in foreign operations.
2012 (unaudited - millions of $ unless noted otherwise) | Power | | Natural gas | | Foreign exchange | | Interest | |
| | | | | | | | | |
Derivative instruments held for trading1 | | | | | | | | |
Fair values2,3 | | | | | | | | |
Assets | $139 | | $88 | | $1 | | $14 | |
Liabilities | $(176 | ) | $(104 | ) | $(2 | ) | $(14 | ) |
Notional values3 | | | | | | | | |
Volumes4 | | | | | | | | |
Sales | 31,066 | | 65 | | - | | - | |
Purchases | 31,135 | | 83 | | - | | - | |
Canadian dollars | - | | - | | - | | 620 | |
U.S. dollars | - | | - | | US 1,408 | | US 200 | |
Net unrealized (losses)/gains in the three months ended March 31, 20125 | $(7 | ) | $(14 | ) | $6 | | $- | |
Net realized (losses)/gains in the three months ended March 31, 20125 | $15 | | $(10 | ) | $9 | | $- | |
| Maturity dates | 2013 -2017 | | 2013-2016 | | 2013 | | 2013-2016 | |
| | | | | | | | | |
Derivative instruments in hedging relationships 6,7 | | | | | | | | |
Fair values2,3 | | | | | | | | |
Assets | $76 | | $- | | $- | | $10 | |
Liabilities | $(97 | ) | $(2 | ) | $(38 | ) | $- | |
Notional values3 | | | | | | | | |
Volumes4 | | | | | | | | |
Sales | 7,200 | | - | | - | | - | |
Purchases | 15,184 | | 1 | | - | | - | |
U.S. dollars | - | | - | | US 12 | | US 350 | |
Cross-currency | - | | - | | 136/US 100 | | - | |
Net realized (losses)/gains in the three months ended March 31, 20125 | $(32 | ) | $(6 | ) | $- | | $1 | |
| Maturity dates | 2013-2018 | | 2013 | | 2013-2014 | | 2013-2015 | |
| 1 | All derivative instruments held for trading have been entered into for risk management purposes and are subject to our risk management strategies, policies and limits. This includes derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage our exposure to market risk. |
| 2 | Fair values equal carrying values. |
| 3 | As at December 31, 2012. |
| 4 | Volumes for power and natural gas derivatives are in GWh and Bcf, respectively. |
| 5 | Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in interest expense and interest income and other, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles. |
| 6 | All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $10 million and a notional amount of US$350 million. For the three months ended March 31, 2012, net realized gains on fair value hedges were $2 million and were included in interest expense. For the three months ended March 31, 2012, we did not record any amounts in net income related to ineffectiveness for fair value hedges. |
| 7 | For the three months ended March 31, 2012, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur. |
FIRST QUARTER REPORT 2013
BALANCE SHEET PRESENTATION OF DERIVATIVE INSTRUMENTS
The fair value of the derivative instruments on the balance sheet.
| (unaudited - millions of $) | March 31, 2013 | | December 31, 2012 | |
| | | | | |
| Current | | | | |
| Other current assets | 248 | | 259 | |
| Accounts payable and other | (302 | ) | (283 | ) |
| Long term | | | | |
| Intangible and other assets | 158 | | 187 | |
| Other long-term liabilities | (193 | ) | (186 | ) |
DERIVATIVES IN CASH FLOW HEDGING RELATIONSHIPS
The components of other comprehensive income (OCI) related to derivatives in cash flow hedging relationships.
Cash flow hedges1 three months ended March 31 | Power | | Natural gas | | Foreign exchange | | Interest |
| (unaudited - millions of $, pre-tax) | 2013 | | 2012 | | 2013 | | 2012 | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | | | | | | | | | |
| Change in fair value of derivative instruments recognized in OCI (effective portion) | 36 | | (66 | ) | - | | (10 | ) | 2 | | (3 | ) | - | | - |
| Reclassification of gains and losses on derivative instruments from AOCI to net income (effective portion) | (11 | ) | 47 | | - | | 13 | | - | | - | | 4 | | 6 |
| Gains and losses on derivative instruments recognized in earnings (ineffective portion) | (5 | ) | (6 | ) | - | | (2 | ) | - | | - | | - | | - |
| 1 | No amounts have been excluded from the assessment of hedge effectiveness. |
CREDIT RISK RELATED CONTINGENT FEATURES
Derivatives contracts often contain financial assurance provisions that may require us to provide collateral if a credit risk-related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade).
Based on contracts in place and market prices at March 31, 2013, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $34 million (December 31, 2012 - $37 million), with collateral provided in the normal course of business of nil (December 31, 2012 - nil). If the credit-risk-related contingent features in these agreements had been triggered on March 31, 2013, we would have been required to provide collateral of $34 million (December 31, 2012 - $37 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.
We feel we have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
FAIR VALUE HIERARCHY
Assets and liabilities that are recorded at fair value are required to be categorized into three levels based on the fair value hierarchy.
FIRST QUARTER REPORT 2013
| Levels | How fair value has been determined |
| | |
| Level I | Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date. |
| Level II | Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and power and natural gas commodity derivatives where fair value is determined using the market approach. |
Level III | Valuation of assets and liabilities measured on a recurring basis using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. This category includes long-dated commodity transactions in certain markets where liquidity is low. Long term electricity prices are estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which we operate. Model inputs include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas is expected to or may result in a lower fair value measurement of contracts included in Level III. |
The fair value of our assets and liabilities measured on a recurring basis, including both current and non-current positions.
| | Quoted prices in active markets (Level I)1 | | Significant other observable inputs (Level II) | | Significant unobservable inputs (Level III) | | Total | |
(unaudited - millions of $, pre-tax) | Mar 31, 2013 | | Dec 31, 2012 | | Mar 31, 2013 | | Dec 31, 2012 | | Mar 31, 2013 | | Dec 31, 2012 | | Mar 31, 2013 | | Dec 31, 2012 | |
| | | | | | | | | | | | | | | | | |
| Derivative instrument assets: | | | | | | | | | | | | | | | | |
Power commodity contracts | - | | - | | 224 | | 213 | | 5 | | 2 | | 229 | | 215 | |
Natural gas commodity contracts | 77 | | 75 | | 8 | | 13 | | - | | - | | 85 | | 88 | |
Foreign exchange contracts | - | | - | | 69 | | 119 | | - | | - | | 69 | | 119 | |
Interest rate contracts | - | | - | | 23 | | 24 | | - | | - | | 23 | | 24 | |
| Derivative instrument liabilities: | | | | | | | | | | | | | | | | |
Power commodity contracts | - | | - | | (275 | ) | (269 | ) | (4 | ) | (4 | ) | (279 | ) | (273 | ) |
Natural gas commodity contracts | (79 | ) | (95 | ) | (15 | ) | (11 | ) | - | | - | | (94 | ) | (106 | ) |
Foreign exchange contracts | - | | - | | (109 | ) | (76 | ) | - | | - | | (109 | ) | (76 | ) |
Interest rate contracts | - | | - | | (13 | ) | (14 | ) | - | | - | | (13 | ) | (14 | ) |
| Non-derivative financial instruments: | | | | | | | | | | | | | | | | |
Available for sale assets | 49 | | 44 | | - | | - | | - | | - | | 49 | | 44 | |
| | 47 | | 24 | | (88 | ) | (1 | ) | 1 | | (2 | ) | (40 | ) | 21 | |
The following table presents the net change in the Level III fair value category.
| three months ended March 31 | Derivatives1 | |
| (unaudited - millions of $, pre-tax) | 2013 | | 2012 | |
| | | | | |
| Balance at January 1 | (2 | ) | (15 | ) |
| Total gains included in OCI | 3 | | 4 | |
| Balance at March 31 | 1 | | (11 | ) |
FIRST QUARTER REPORT 2013
| 1 | For the three months ended March 31, 2013, the unrealized gains or losses included in net income attributed to derivatives in the Level III category that were still held at the reporting date was nil (2012 - nil). |
A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $3 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III at March 31, 2013.
FIRST QUARTER REPORT 2013
Other information
CONTROLS AND PROCEDURES
Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 2013, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
There were no changes in first quarter 2013 that had or are likely to have a material impact on our internal control over financial reporting.
Management is in the process of implementing an Enterprise Resource Planning (ERP) system that will likely affect some processes supporting internal control over financial reporting in subsequent quarters of 2013. The phased implementation period is planned to begin July 1, 2013.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, AND ACCOUNTING CHANGES
When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgment. We also regularly assess the assets and liabilities themselves.
Our significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2012. You can find a summary of our significant accounting policies and critical accounting estimates in our 2012 Annual Report.
Changes in accounting policies for 2013
Balance sheet offsetting
Effective January 1, 2013, we adopted the Accounting Standards Update (ASU) on disclosures about balance sheet offsetting as issued by the Financial Accounting Standards Board (FASB) to enable understanding of the effects of netting arrangements on our financial position. Adoption of the ASU has resulted in increased qualitative and quantitative disclosures about certain derivative instruments that are either offset in accordance with current U.S. GAAP or are subject to a master netting arrangement or similar agreement.
Accumulated other comprehensive income
Effective January 1, 2013, we adopted the ASU on reporting of amounts reclassified out of accumulated other comprehensive income (AOCI) as issued by the FASB. Adoption of the ASU has resulted in providing additional qualitative and quantitative disclosures about significant amounts reclassified out of AOCI into net income.
Future accounting changes
Obligations resulting from joint and several liability arrangements
In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This ASU is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. We are evaluating the impact that adopting the ASU would have on our consolidated financial statements, but do not expect it to be material.
Foreign currency matters - cumulative translation adjustment
In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This ASU is effective prospectively for fiscal years, and interim reporting periods within those years, beginning after December 15, 2013. Early adoption is allowed as of the beginning of the entity's fiscal year. We are evaluating the impact that adopting this ASU would have on our consolidated financial statements, but do not expect it to be material.
FIRST QUARTER REPORT 2013
QUARTERLY RESULTS
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
(millions of $, except per share amounts)
| | 2013 | | 2012 | | 2011 |
| (unaudited) | First | | Fourth | Third | Second | First | | Fourth | | Third | | Second |
| | | | | | | | | | | | | |
| Revenues | 2,252 | | 2,089 | 2,126 | 1,847 | 1,945 | | 2,015 | | 2,043 | | 1,851 |
| Net income attributable to common shares | 446 | | 306 | 369 | 272 | 352 | | 376 | | 386 | | 353 |
| | | | | | | | | | | | | |
| Share Statistics | | | | | | | | | | | | |
| Net Income per common share - basic and diluted | $0.63 | | $0.43 | $0.52 | $0.39 | $0.50 | | $0.53 | | $0.55 | | $0.50 |
Dividend declared per common share | $0.46 | | $0.44 | $0.44 | $0.44 | $0.44 | | $0.42 | | $0.42 | | $0.42 |
FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT
Quarter-over-quarter revenues and net incomes sometimes fluctuate. The causes of this fluctuation vary across our business segments.
In Natural Gas Pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:
| · | negotiated settlements with shippers |
| · | seasonal fluctuations in short-term throughput volumes on U.S. pipelines |
| · | acquisitions and divestitures |
| · | developments outside of the normal course of operations |
| · | newly constructed assets being placed in service. |
In Oil Pipelines, annual revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable.
In Energy, quarter-over-quarter revenues and net income are affected by:
| · | capacity prices and payments |
| · | planned and unplanned plant outages |
| · | acquisitions and divestitures |
| · | certain fair value adjustments |
| · | developments outside of the normal course of operations |
| · | newly constructed assets being placed in service. |
FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER
First quarter 2013
| · | EBIT included $42 million of pre-tax income ($84 million after-tax) from the Canadian Restructuring Proposal relating to 2012 and net unrealized losses of $10 million pre-tax ($8 million after-tax) from certain risk management activities. |
Fourth quarter 2012
| · | EBIT included net unrealized losses of $17 million pre-tax ($12 million after-tax) from certain risk management activities. |
Third quarter 2012
| · | EBIT included net unrealized gains of $31 million pre-tax ($20 million after-tax) from certain risk management activities. |
FIRST QUARTER REPORT 2013
Second quarter 2012
| · | EBIT included a $50 million pre-tax charge ($37 million after-tax) from the Sundance A PPA arbitration decision, and net unrealized losses of $14 million pre-tax ($13 million after-tax) from certain risk management activities. |
First quarter 2012
| · | EBIT included net unrealized losses of $22 million pre-tax ($11 million after-tax) from certain risk management activities. |
Fourth quarter 2011
| · | EBIT included net unrealized gains of $13 million pre-tax ($11 million after-tax) from certain risk management activities. |
Third quarter 2011
| · | EBIT included net unrealized losses of $43 million pre-tax ($30 million after-tax) from certain risk management activities. |
Second quarter 2011
| · | EBIT included net unrealized losses of $3 million pre-tax ($2 million after-tax) from certain risk management activities. |
