CALGARY, ALBERTA — (Marketwired) — 11/04/14 — TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada) today announced net income attributable to common shares for third quarter 2014 of $457 million or $0.64 per share compared to $481 million or $0.68 per share for the same period in 2013. Comparable earnings for third quarter 2014 were $450 million or $0.63 per share compared to $447 million or $0.63 per share for the same period last year. TransCanada–s Board of Directors also declared a quarterly dividend of $0.48 per common share for the quarter ending December 31, 2014, equivalent to $1.92 per common share on an annualized basis.
“Our three core businesses generated solid earnings and cash flow during the quarter,” said Russ Girling, TransCanada–s president and chief executive officer. “Contributions from new assets like the Keystone Gulf Coast Extension and the Tamazunchale Extension in Mexico, along with strong results from Bruce Power, highlight the benefits of a diversified and growing portfolio of pipeline and power assets. We are also pleased to have announced an additional $4.7 billion of new capital projects highlighting the organic growth opportunities that are tied to our unparalleled asset footprint.”
Since the beginning of 2014, we have captured $6.6 billion of capital projects related to our Canadian regulated natural gas pipeline assets. This includes $2.7 billion of new investment associated with the NGTL System, $2 billion of expansions and facility modifications to the Canadian Mainline in Ontario and the previously announced $1.9 billion Merrick Mainline Pipeline Project. With these additions, our capital program now totals $46 billion of commercially secured projects, essentially all of which are backed by long-term contracts or cost of service business models. This growth portfolio includes $24 billion of liquids pipelines, $20 billion of natural gas pipelines and $2 billion of power generation facilities. We continue to advance this unprecedented slate of growth initiatives, with many currently proceeding through their respective regulatory processes. Over the remainder of the decade, subject to required approvals, this blue-chip portfolio of contracted energy infrastructure is expected to generate significant sustainable growth in earnings, cash flow and dividends.
On October 1, 2014, we closed the sale of our remaining 30 per cent interest in Bison Pipeline LLC (Bison) to our master limited partnership, TC PipeLines, LP (the Partnership) for cash proceeds of US$215 million. This transaction underscores our commitment to drop down all of our remaining U.S. natural gas pipeline assets to the Partnership on a more sizable and more frequent basis over the coming quarters and years. This will provide us with significant cash proceeds and is an important element of funding our unprecedented growth portfolio, while enhancing the size and diversity of the Partnership–s asset base, positioning it with visible, high quality future growth.
Looking forward, our current asset base and financial strength positions us well to generate significant long-term shareholder value through execution of our industry-leading capital program and our commitment to continuously evaluate our approach to capital allocation.
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Net income attributable to common shares decreased by $24 million to $457 million or $0.64 per share for the three months ended September 30, 2014 compared to the same period in 2013 and, in both years, included unrealized gains and losses from changes in certain risk management activities.
Comparable earnings for third quarter 2014 were $450 million or $0.63 per share compared to $447 million or $0.63 per share for the same period in 2013. Higher earnings from Keystone, Mexican Pipelines and U.S. Power were offset by lower contributions from Western Power, U.S. Pipelines and Gas Storage.
Notable recent developments in Liquids Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Liquids Pipelines:
Natural Gas Pipelines:
Energy:
Corporate:
Teleconference – Audio and Slide Presentation:
We will hold a teleconference and webcast on Tuesday, November 4, 2014 to discuss our third quarter 2014 financial results. Russ Girling, TransCanada president and chief executive officer, and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 9 a.m. (MT) / 11 a.m. (ET).
Analysts, members of the media and other interested parties are invited to participate by calling 866.223.7781 or 416.340.2216 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at .
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on November 11, 2014. Please call 800.408.3053 or 905.694.9451 and enter pass code 1306125.
The unaudited interim Consolidated Financial Statements and Management–s Discussion and Analysis (MD&A) are available under TransCanada–s profile on SEDAR at , with the U.S. Securities and Exchange Commission on EDGAR at and on the TransCanada website at .
With more than 60 years– experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 68,500 kilometres (42,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent–s largest providers of gas storage and related services with more than 400 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 11,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America–s largest oil delivery systems. TransCanada–s common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: or check us out on Twitter @TransCanada or .
Forward Looking Information
This news release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as “anticipate”, “expect”, “believe”, “may”, “will”, “should”, “estimate”, “intend” or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management–s assessment of TransCanada–s and its subsidiaries– future plans and financial outlook. All forward-looking statements reflect TransCanada–s beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to TransCanada–s Quarterly Report to Shareholders dated November 3, 2014 and 2013 Annual Report on our website at or filed under TransCanada–s profile on SEDAR at and with the U.S. Securities and Exchange Commission at .
Non-GAAP Measures
This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, funds generated from operations and comparable earnings per share, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada–s Quarterly Report to Shareholders dated November 3, 2014.
Management–s discussion and analysis
November 3, 2014
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 three and nine months ended September 30, 2014, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2014 which have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our December 31, 2013 audited consolidated financial statements and notes and the MD&A in our 2013 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 2013 Annual Report.
All information is as of November 3, 2014 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:
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
Risks and uncertainties
You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2013 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 ().
NON-GAAP MEASURES
We use the following non-GAAP measures:
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 financial charges, income tax, 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 a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings. 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 a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period and is used to provide a consistent measure of the cash generating performance of our assets. See the 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.
Our decision not to include a specific item is subjective and made after careful consideration. Specific items may include:
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.
Net income attributable to common shares decreased by $24 million for the three months ended September 30, 2014 compared to the same period in 2013. Net Income included unrealized gains and losses from changes in certain risk management activities. Excluding the impact of these items, comparable earnings in the three months ended September 30, 2014 increased slightly over the same period in 2013, as discussed below in Reconciliation of Net Income to Comparable Earnings.
Net income attributable to common shares decreased by $7 million for the nine months ended September 30, 2014 compared to the same period in 2013. The 2014 results included:
The results for the first nine months of 2013 included $84 million of Canadian Mainline net income related to 2012 resulting from an NEB decision in April 2013 (RH-003-2011) as well as a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax in June 2013.
The items discussed above are excluded from comparable earnings for the relevant periods. The remainder of net income is equivalent to comparable earnings. A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.
Comparable earnings increased by $3 million for the three months ended September 30, 2014 compared to the same period in 2013. This was primarily the net effect of:
Comparable earnings increased by $30 million or $0.04 per share for the nine months ended September 30, 2014 compared to the same period in 2013. This was primarily the net effect of:
The stronger U.S. dollar this quarter compared to the same period in 2013 positively impacted the translated results in our U.S. businesses, however this impact was mostly offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our net exposure through our hedging program.
CAPITAL PROGRAM
We are developing quality projects under our long-term capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cashflow.
Our capital program is comprised of $17 billion of small to medium-sized projects and $29 billion of large scale projects. Amounts presented exclude the impact of foreign exchange and capitalized interest. All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.
Outlook
The earnings outlook previously included in the 2013 Annual Report is expected to be impacted by:
We expect our capital expenditures to be $4 billion for 2014, a decrease of $1 billion from the outlook previously disclosed in our 2013 Annual Report.
See the MD&A in our 2013 Annual Report for further information about our outlook.
Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).
Natural Gas Pipelines segmented earnings increased by $48 million and $183 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. Natural Gas Pipelines segmented earnings for the nine months ended September 30, 2013 included $42 million related to the 2012 impact of the NEB decision (RH-003-2011). This amount has been excluded in our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT and comparable EBITDA and are discussed below.
CANADIAN PIPELINES
Net income and comparable EBITDA for our rate-regulated Canadian pipelines are affected by the approved ROE, investment base, level of deemed common equity, carrying charges accrued to shippers on the Tolls Stabilization Account (TSA), and incentive earnings. Changes in depreciation, financial charges and taxes also impact comparable EBITDA and comparable EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.
Net income for the Canadian Mainline decreased by $6 million and $100 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. Net income in first quarter 2013 included $84 million related to the 2012 impact of the NEB decision (RH-003-2011), which was excluded from comparable earnings. Comparable earnings in both years reflect an ROE of 11.50 per cent on deemed common equity of 40 per cent and have decreased by $6 million and $16 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 because of a lower average investment base as well as carrying charges accrued to shippers on the positive TSA.
Net income for the NGTL System increased by $4 million and $11 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. A higher average investment base as well as an increase in the ROE had a positive impact on earnings. These increases were partially offset by increased OM&A costs at risk under the terms of the 2013-2014 NGTL Settlement approved by the NEB in November 2013. The Settlement included an ROE of 10.10 per cent on deemed common equity of 40 per cent and included annual fixed amounts for certain OM&A costs. Results for the three and nine months ended September 30, 2013 reflect the previously approved ROE of 9.70 per cent on deemed common equity of 40 per cent.
U.S. AND INTERNATIONAL PIPELINES
Earnings for our U.S. natural gas pipelines operations are 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 increased by US$6 million and US$55 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. This was the net effect of:
A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.
COMPARABLE DEPRECIATION AND AMORTIZATION
Comparable depreciation and amortization increased by $18 million and $58 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 mainly because of a higher investment base and higher depreciation rates on the NGTL System.
BUSINESS DEVELOPMENT
Business development expenses were lower by $12 million and $15 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 mainly due to recovery of amounts from partners for 2013 Alaska Gasline Inducement Act costs in 2014 and lower general and administrative expenses.
OPERATING STATISTICS – WHOLLY OWNED PIPELINES
Liquids Pipelines(1)
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).
Liquids Pipelines segmented earnings increased by $74 million and $170 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. Liquids Pipelines segmented earnings are equivalent to comparable EBIT and comparable EBITDA and are discussed below.
Comparable EBITDA for the Keystone Pipeline System is generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings.
Comparable EBITDA for the Keystone Pipeline System increased by $82 million and $213 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. These increases were primarily due to:
BUSINESS DEVELOPMENT
Business development expenses for the three and nine months ended September 30, 2014 were $10 million and $4 million lower than the same periods in 2013 mainly due to lower general and administrative expenses and an increased focus on capital projects.
COMPARABLE DEPRECIATION AND AMORTIZATION
Comparable depreciation and amortization increased by $18 million and $47 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 due to the Gulf Coast extension being placed in service.
Energy
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).
Energy segmented earnings decreased by $11 million for the three months ended September 30, 2014 and increased by $20 million for the nine months ended September 30, 2014 compared to the same periods in 2013.
Energy segmented earnings included the following specific items:
The remainder of the Energy segmented earnings are equivalent to comparable EBITDA and comparable EBIT and are discussed below.
Comparable EBITDA for Energy decreased by $23 million and $54 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 due to:
Results for the nine months ended September 30, 2014 were also impacted by higher realized power prices at U.S. Power.
A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.
Sales volumes and plant availability
Includes our share of volumes from our equity investments.
Western Power
Comparable EBITDA for Western Power decreased by $38 million and $111 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 due to the net effect of:
Average spot market power prices in Alberta decreased by 24 per cent from $84/MWh to $64/MWh for the three months ended September 30, 2014 and 38 per cent from $90/MWh to $56/MWh for the nine months ended September 30, 2014, compared to the same periods in 2013. Strong coal fleet availability and new wind capacity in the Alberta market have resulted in significantly lower prices despite strong growth in Alberta power demand. Realized power prices on power sales can be higher or lower than spot market power prices in any given period as a result of contracting activities.
Seventy-five per cent of Western Power sales volumes were sold under contract in third quarter 2014 and 70 per cent in third quarter 2013.
Eastern Power
Comparable EBITDA for Eastern Power increased by $4 million and $8 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 mainly due to the incremental earnings from the four Ontario solar facilities acquired in 2013. Comparable EBITDA for the nine months ended September 30, 2014 was also impacted by lower earnings from Halton Hills.
BRUCE POWER
Our proportionate share
Equity income from Bruce A increased by $17 million for the three months ended September 30, 2014 compared to the same period in 2013. The increase was mainly due to lower depreciation and operating expenses. The negative impact of increased outage days was generally offset by higher generation levels while operating.
Equity income from Bruce A decreased by $23 million for the nine months ended September 30, 2014 compared to the same period in 2013 mainly due to:
These decreases were partially offset by higher earnings from Unit 4 following the completion of the planned life extension outage which began in third quarter 2012 and was completed in April 2013.
Equity income from Bruce B decreased $11 million for the three months ended September 30, 2014 compared to the same period in 2013 mainly due to higher lease expense recognized in third quarter 2014 based on the terms of the lease agreement with Ontario Power Generation.
Equity income from Bruce B increased $27 million for the nine months ended September 30, 2014 compared to the same period in 2013 mainly due to higher volumes and lower operating costs resulting from fewer planned and unplanned outage days, partially offset by higher lease expense.
Under the contract with the OPA, all of the output from Bruce A Units 1 to 4 is sold at a fixed price per MWh. The fixed price is adjusted annually on April 1 for inflation and other provisions under the OPA contract. Bruce A also recovers fuel costs from the OPA.
Under the same contract, all output from Bruce B Units 5 to 8 is subject to a floor price adjusted annually for inflation on April 1.
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the average spot price in a month exceeds the floor price. While the first quarter 2014 average spot price exceeded the floor price, spot prices have since fallen below the floor price and are expected to remain there for the remainder of 2014. As a result, Bruce B is expected to recognize annual revenues at the floor price and amounts equivalent to that received above the floor in first quarter 2014 are expected to be repaid to the OPA in early 2015.
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 2014 is expected to be in the high 70s for Bruce A and high 80s for Bruce B. Bruce B Unit 5 was removed from service early in October 2014 for a planned maintenance outage which is scheduled for approximately two months.
Comparable EBITDA for U.S. Power increased US$6 million for the three months ended September 30, 2014 compared to the same period in 2013. The increase was the net effect of:
Comparable EBITDA for U.S. Power increased US$33 million for the nine months ended September 30, 2014 compared to the same period in 2013. The increase was the net effect of:
Wholesale electricity prices in New York and New England were lower for the three months ended September 30, 2014 compared to the same period in 2013 primarily due to cooler summer temperatures. Wholesale electricity prices in New York and New England were higher for the nine months ended September 30, 2014 compared to the same period in 2013 primarily due to significantly higher spot power prices in first quarter 2014. Colder winter temperatures and gas transmission constraints resulted in higher natural gas prices in the predominantly gas-fired New England and New York power markets in first quarter 2014 compared to the same period in 2013.
Average spot power prices for the three months ended September 30, 2014 in New England of US$34/MWh were 20 per cent lower and in New York City spot power prices decreased 34 per cent to an average of US$34/MWh compared to the same period in 2013. Average spot power prices for the nine months ended September 30, 2014 in New England increased 29 per cent to US$73/MWh and in New York City spot power prices increased 20 per cent to an average of US$66/MWh compared to the same period in 2013.
Average spot capacity prices in New York City of US$18 and US$15 per kilowatt-month were on average 17 per cent and 32 per cent higher for the three and nine months ended September 30, 2014 compared to the same periods in 2013. This, and the impact of hedging activities, resulted in higher realized capacity prices in New York compared to the same period in 2013.
Physical sales volumes for the three and nine months ended September 30, 2014 were higher than the same periods in 2013. For the three months ended September 30, 2014, generation volumes at our Ravenswood facility and purchased volumes sold to wholesale, commercial and industrial customers were higher than the same period in 2013. For the nine months ended September 30, 2014, generation at our Ravenswood and Kibby facilities and purchased volumes sold to wholesale, commercial and industrial customers were also higher than in the same period in 2013.
As at September 30, 2014, approximately 1,500 GWh or 70 per cent of U.S. Power–s planned generation was contracted for the remainder of 2014, and 3,500 GWh or 35 per cent for 2015. 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 AND OTHER
Comparable EBITDA decreased $6 million and $4 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. The decrease was primarily due to lower realized natural gas storage spreads. The seasonal nature of natural gas storage generally results in higher revenues in the winter season.
Recent developments
NATURAL GAS PIPELINES
Canadian Regulated Pipelines
NGTL System
We continue to experience significant growth on the NGTL System as a result of growing natural gas supply in northwestern Alberta and northeastern B.C. from unconventional gas plays and substantive growth in intra-basin delivery markets. This is driven primarily by oil sands development and demand for gas-fired electric power generation. This demand for NGTL System services is expected to result in approximately 4.0 Bcf/d of incremental firm receipt and firm delivery services. Approximately 3.1 Bcf/d relates to firm receipt services and 0.9 Bcf/d relates to firm delivery services. As a result, following NEB approval, we will be constructing new facilities to meet these service requests of approximately 540 km (336 miles) of pipeline, seven compressor stations, and 40 meter stations which will be required in 2016 and 2017 (2016/17 Facilities). The estimated total capital costs for the facilities is approximately $2.7 billion.
Approximately $285 million of capital projects have been placed in service in the nine months ended September 30, 2014. Including the new 2016/17 Facilities capital requirements, we have approximately $6.7 billion of projects in development or under construction, which have been or will be filed with the NEB for approval. This includes the North Montney Mainline and the Merrick Mainline Pipeline, along with other new supply and demand facilities.
North Montney Mainline Project
The NEB issued a Hearing Order in February 2014 for the $1.7 billion North Montney Pipeline Project, which is an extension and expansion of the NGTL System to receive and transport natural gas from the North Montney area of B.C. The proposed project consists of approximately 300 km (186 miles) of pipeline and is expected to be in service in two sections, Aitken Creek in second quarter 2016 and Kahta in second quarter 2017.
On June 17, 2014, the NEB revised the procedural schedule which has resulted in the oral portion of the hearing being rescheduled. The Calgary phase began October 14, 2014 and the Fort St. John phase is to be begin in mid-November. We now anticipate an NEB decision on the application in first quarter 2015.
Merrick Mainline Pipeline Project
On June 4, 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.
The proposed Merrick Mainline Pipeline Project will transport natural gas sourced through the NGTL System to the inlet of a proposed Pacific Trail Pipeline that will terminate at the Kitimat LNG Terminal at Bish Cove near Kitimat, B.C. The proposed project will be an extension from the existing Groundbirch Mainline section of the NGTL System beginning near Dawson Creek, B.C. to its end point near the community of Summit Lake, B.C. The $1.9 billion project consists of approximately 260 km (161 miles) of 48-inch diameter pipe.
The filing of the application for approvals to build and operate the system with the NEB is under review and is likely to be delayed to first quarter 2015. Subject to the necessary approvals, including a positive final investment decision for the Kitimat LNG project, we expect the Merrick Mainline to be in service in first quarter 2020.
2015 Revenue Requirement Settlement
We have reached a revenue requirement settlement with our shippers for 2015 on the NGTL System. The terms of the one year settlement include no changes to the return on equity 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 operating, maintenance and administrative expense amount. The settlement was filed with the NEB on October 31, 2014.
Canadian Mainline
LDC Settlement
In 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. In May 2014, the NEB released a Hearing Order that set out a hearing process and schedule for the 2015 – 2030 Mainline Tolls application that incorporates the LDC Settlement. The hearing concluded September 25, 2014 and we anticipate a decision from the NEB before the end of 2014.
Eastern Mainline Project
In May 2014, we filed a project description with the NEB for the Eastern Mainline Project. On October 30, 2014 we filed an application seeking NEB approval to build, own and operate new facilities for our existing Canadian Mainline natural gas transmission system in southeastern Ontario. The new facilities are a result of the proposed transfer of a portion of the Canadian Mainline capacity to crude oil from natural gas service as part of our Energy East Pipeline and an open season that closed in January 2014. The $1.5 billion capital project will add 0.6 Bcf/d of new capacity and will ensure appropriate levels of capacity are available to meet the requirements of existing shippers as well as new firm service commitments in the Eastern Triangle segment of the Canadian Mainline. Subject to regulatory approvals, the project is expected to be in service by second quarter 2017.
Other Canadian Mainline Expansions
In addition to the Eastern Mainline Project, we have executed new short haul arrangements in the Eastern Triangle portion of the Canadian Mainline that require new, or modifications to existing facilities with a total capital cost estimate of $475 million. Approximately $255 million of these projects have an expected in-service date of November 1, 2015 including the Kings North Connection, Parkway West Connection and the Hamilton Area Project. The Vaughan Loop and compressor station piping modifications, with a capital cost of approximately $220 million, have an expected in-service date of November 1, 2016. These projects are subject to regulatory approval and, once constructed, will provide capacity needed to meet customer requirements in Eastern Canada.
U.S. Pipelines
Sale of Bison Pipeline to TC PipeLines, LP
On October 1, 2014, we closed the sale of our remaining 30 per cent interest in Bison Pipeline LLC to TC PipeLines, LP for cash proceeds of US$215 million plus purchase price adjustments.
At September 30, 2014, we held a 28.3 per cent interest in TC PipeLines, LP for which we are the General Partner.
ANR Pipeline
We have secured almost 2.0 Bcf/d of firm natural gas transportation commitments on the ANR Pipeline–s Southeast Main Line at maximum rates for an average term of 23 years. Approximately 1.25 Bcf/d of new contracts will commence in late 2014 including volume commitments from the ANR Lebanon Lateral Reversal project, with the remaining volume commencing in 2015. These contracts will enable growing Utica and Marcellus shale gas supply to move to both northern delivery points and southbound to the U.S. Gulf Coast. As a result, approximately US$100 million of capital investment will be required to bring this additional supply to market.
Mexican Pipelines
Tamazunchale Pipeline Extension Project
Construction of the US$600 million extension is now expected to be completed in fourth quarter 2014 with delays attributed to archeological findings along the pipeline route. Under the terms of the Transportation Service Agreement, these delays are recognized as a force majeure with provisions allowing for collection of revenue as per the original service commencement of March 9, 2014.
LNG Pipeline Projects
Coastal GasLink
On October 24, 2014, the B.C. EAO issued the Environmental Assessment Certificate which contains 32 conditions, the majority of which reflect current best practices for natural gas pipeline construction and operation.
In first quarter 2014 we commenced the phased filing of the B.C. Oil and Gas Commission applications required for the construction and operation of the pipeline facilities. Regulatory review of those applications is progressing on schedule, with permit decisions anticipated in first quarter 2015.
We are currently progressing the engineering design work to support the regulatory applications and refine the capital cost estimates for the final investment decision which is expected to be made by LNG Canada in early 2016.
Prince Rupert Gas Transmission
We continue to support information requests related to the regulatory applications with the B.C. EAO and B.C. Oil and Gas Commission. Work continues towards refining a capital cost estimate for the final investment decision which is expected to be made by Pacific NorthWest LNG by the end of 2014.
Alaska
On July 16, 2014, the producers filed an export permit application with the U.S. Department of Energy for the right to export 20 million tonnes per annum of liquefied natural gas for 30 years. On September 12, 2014, the FERC approved the National Environmental Policy Act (NEPA) pre-file request jointly made by us, the three major Alaska North Slope producers and Alaska Gasline Development Corp. This approval triggers the NEPA environmental review process, which includes a series of community consultations.
LIQUIDS PIPELINES
Keystone Pipeline System
In early 2014, we completed construction of the 780 km (485 mile) Gulf Coast extension of the Keystone Pipeline System, from Cushing, Oklahoma to the U.S. Gulf Coast. Crude oil transportation service on the project began January 22, 2014.
Keystone XL
On January 31, 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. On April 18, 2014, the DOS announced that the National Interest Determination period has been extended indefinitely to allow them to consider the potential impact of the case discussed below on the Nebraska portion of the pipeline route.
In February 2014, a Nebraska district court ruled that the state Public Service Commission, rather than Governor Dave Heineman, has the authority to approve an alternative route through Nebraska for the Keystone XL project. Nebraska–s Attorney General has filed an appeal and the Nebraska State Supreme Court heard the appeal on September 5, 2014. It is unknown when the Nebraska State Supreme Court will release its decision.
On September 15, 2014, we filed a certification petition for Keystone XL with the South Dakota Public Utilities Commission (PUC). This certification confirms that the conditions under which Keystone XL–s original June 2010 PUC construction permit was granted persist. It is unknown when the South Dakota PUC will release its decision.
Due to continued delays in acquiring U.S. regulatory approvals and increasing regulatory conditions, the estimated capital costs for the Keystone XL project have increased from US$5.4 billion as provided in the DOS regulatory filing to approximately US$8.0 billion. As of September 30, 2014, we have invested US$2.4 billion in the Keystone XL project.
Cushing Marketlink
In September 2014, we completed construction on the Cushing Marketlink receipt facilities at Cushing, Oklahoma. Cushing Marketlink will facilitate the transportation of crude oil from the market hub at Cushing to the U.S. Gulf Coast refining market on facilities that form part of the Keystone Pipeline System.
Energy East Pipeline
In March 2014, we filed the project description for the Energy East Pipeline with the NEB. This is the first formal step in the regulatory process to receive the necessary approvals to build and operate the pipeline. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets.
We continue to participate in Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning.
On October 30, 2014, we filed the necessary regulatory applications for approvals to construct and operate the pipeline project and terminal facilities with the NEB. Subject to regulatory approvals, the pipeline is anticipated to commence deliveries to Quebec and New Brunswick by the end of 2018.
Heartland Pipeline and TC Terminals
The Heartland Pipeline and TC Terminals will include a 200 km (125 mile) crude oil pipeline connecting the Edmonton/Heartland, Alberta market region to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton, Alberta. In February 2014, the application for the terminal facility was approved by the Alberta Energy Regulator.
Grand Rapids Pipeline
On October 9, 2014, the Alberta Energy Regulator (AER) issued a permit approving the majority of our application to construct and operate the Grand Rapids Pipeline. Construction is expected to begin in fall 2014, with the system expected to be in service in multiple stages with initial crude oil service by mid-2016 and full completion in 2017.
Northern Courier Pipeline
In October 2013, Suncor Energy announced that Fort Hills Energy LP is proceeding with the Fort Hills oil sands mining project and expects to begin producing crude oil in 2017. Our Northern Courier Pipeline project will transport bitumen and diluent between the Fort Hills mine site and Suncor Energy–s terminal located north of Fort McMurray, Alberta.
In July 2014, the AER issued a permit approving our application to construct and operate the Northern Courier Pipeline. Construction has commenced and the pipeline is expected to be in service in 2017.
ENERGY
Ontario Solar
At the end of September 2014, we completed the acquisition of three additional Ontario solar facilities for $181 million. All power produced by the solar facilities will be sold under 20-year PPAs with the OPA.
Ravenswood
In late September 2014, the 972 MW Unit 30 at the Ravenswood Generating Station experienced an unplanned outage as a result of a problem with the generator associated with the high pressure turbine. Insurance is expected to cover the repair costs and lost revenues associated with the unplanned outage, which are yet to be finalized. 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.
Genesee
In October 2014, we acquired a 100MW energy contract from the Alberta Balancing Pool. The contract includes a monthly capacity payment for a three year term, commencing on November 1, 2014, and is derived from the 762 MW Genesee Power Purchase Arrangement (PPA) held by the Alberta Balancing Pool.
Cancarb Limited and Cancarb Waste Heat Facility
The sale of Cancarb Limited and its related power generation facility closed in April 2014 for gross proceeds of $190 million. We recognized a gain of $99 million, net of tax, in second quarter 2014.
Natural Gas Storage
Effective April 30, 2014, we terminated a 38 Bcf long-term natural gas storage contract in Alberta with Niska Gas Storage. The contract contained provisions allowing for possible early termination. As a result, we recorded an after tax charge of $32 million in 2014. We have re-contracted for new natural gas storage services in Alberta with Niska Gas Storage starting May 1, 2014 for a six-year period and a reduced average volume.
Other income statement items
The following are reconciliations and related analyses of our non-GAAP measures to the equivalent GAAP measures.
Comparable interest expense increased by $69 million and $131 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 because of the following:
Comparable interest income and other increased by $33 million and $40 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. This is the result of increased AFUDC related to our rate-regulated projects, including Energy East Pipeline and Mexico pipelines, offset by higher realized losses in 2014 compared to 2013 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income and the impact of a fluctuating U.S. dollar on the translation of foreign currency denominated working capital.
Comparable income tax expense increased by $58 million and $152 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. The increase was mainly the result of higher pre-tax earnings in 2014 compared to 2013, changes in the proportion of income earned between Canadian and foreign jurisdictions as well as higher flow-through taxes in 2014 on Canadian regulated pipelines.
Net income attributable to non-controlling interests decreased by $8 million for the three months ended September 30, 2014 compared to the same period in 2013 primarily due to the redemption of Series U preferred shares in October 2013 and Series Y preferred shares in March 2014.
Net income attributable to non-controlling interests increased by $23 million for the nine months ended September 30, 2014 compared to the same period in 2013 primarily due to the sale of a 45 per cent interest in each of GTN and Bison to TC PipeLines, LP in July 2013 partially offset by the redemption of Series U preferred shares in October 2013 and Series Y preferred shares in March 2014.
Preferred share dividends increased by $4 million and $17 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013. The three month variance is due to the issuance of Series 9 preferred shares in January 2014 and the nine month variance is due to the issuances of Series 7 preferred shares in March 2013 and Series 9 preferred shares in January 2014.
Financial condition
We strive to maintain strong financial capacity and flexibility in all parts of an economic cycle, and rely on our cash flow from operations to sustain our business, pay dividends and fund a portion of our growth.
We believe we have the capacity to fund our existing capital program through predictable cash flow from operations, access to capital markets, cash on hand and substantial committed credit facilities.
We access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings.
Net cash provided by operations increased by $124 million and $675 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013 primarily due to changes in our operating working capital.
At September 30, 2014, our current assets were $3.4 billion and current liabilities were $6.6 billion, leaving us with a working capital deficit of $3.2 billion compared to $2.2 billion at December 31, 2013. This working capital deficiency is considered to be in the normal course of business and is managed through our ability to generate cash flow from operations and our ongoing access to the capital markets.
Capital expenditures in 2014 were primarily related to the construction of Mexico pipelines, expansion of the NGTL System, and construction of the Houston Lateral and Tank Terminals.
Equity investments have increased year-over-year primarily due to our investment in Grand Rapids.
In September 2014, we completed the acquisition of three additional Ontario solar facilities for $181 million.
In April 2014, we closed the sale of Cancarb Limited for $187 million, net of transaction costs.
PREFERRED SHARE ISSUANCE AND REDEMPTION
In January 2014, we completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $450 million. Investors are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly. The dividend rate will reset on October 30, 2019 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 2.35 per cent. The preferred shares are redeemable by us on or after October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends. Investors will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 and on October 30 of every fifth year thereafter. The holders of Series 10 preferred shares 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 and 2.35 per cent.
In March 2014, we redeemed all four million Series Y preferred shares of TCPL at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends. The total face value of the outstanding Series Y Shares was $200 million and carried an aggregate of $11 million in annualized dividends.
The net proceeds of the above debt and preferred share offerings were used for general corporate purposes and to reduce short-term indebtedness.
TC PIPELINES, LP AT-THE-MARKET (ATM) EQUITY ISSUANCE PROGRAM
Beginning in August 2014, TC PipeLines, LP began its at-the-market equity issuance program (ATM Program). TC PipeLines, LP may offer and sell common units having an aggregate offering price of up to US$200 million. Net proceeds from sales under the program will be used for general partnership purposes, which may include debt repayment and future acquisitions.
From August until September 30, 2014, 1.3 million common units were issued under the ATM program generating net proceeds of approximately US$73 million. Our ownership interest in TC PipeLines, LP will decrease as a result of the ATM program. The issuance did not significantly impact our income in third quarter 2014.
DIVIDENDS
On November 3, 2014, we declared quarterly dividends as follows:
SHARE INFORMATION
CREDIT FACILITIES
We use committed revolving credit facilities to support our commercial paper programs and, along with demand facilities, for general corporate purposes including issuing letters of credit as well as providing additional liquidity.
At September 30, 2014, we had $6.5 billion in unsecured credit facilities, including:
See Financial risks and financial instruments for more information about liquidity, market and other risks.
CONTRACTUAL OBLIGATIONS
Our capital commitments have decreased by approximately $400 million since December 31, 2013 primarily due to the completion or advancement of capital projects. Our other purchase obligations have decreased by approximately $500 million since December 31, 2013 primarily due to re-contracting for natural gas storage services in Alberta for a shorter period and a reduced average volume. There were no other material changes to our contractual obligations in third quarter 2014 or to payments due in the next five years or after. See the MD&A in our 2013 Annual Report for more information about our contractual obligations.
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.
See our 2013 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2013.
LIQUIDITY RISK
We manage our liquidity risk by continuously forecasting our cash requirements for a rolling twelve 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:
We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At September 30, 2014 we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration of $224 million with one counterparty at September 30, 2014 (December 31, 2013 – $240 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 AND INTEREST RATE 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. dollar-denominated operations continue to grow, our exposure to changes in currency exchange rates increases. Some of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.
We have floating interest rate debt which subjects us to interest rate cash flow risk. We manage this using a combination of interest rate swaps and options.
Average exchange rate – U.S. to Canadian dollars
The impact of changes in the value of the U.S. dollar on our U.S. dollar-denominated operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below.
Significant U.S. dollar-denominated amounts
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, foreign exchange forward contracts and foreign exchange options. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:
The balance sheet classification of the fair value of derivatives used to hedge our net investment in foreign operations is as follows:
FINANCIAL INSTRUMENTS
All financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.
Non-derivative financial instruments
Fair value of non-derivative financial instruments
The fair value of our notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt has been estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data providers. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.
Certain non-derivative financial instruments including cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that equal their fair value due to the nature of the item or the short time to maturity.
Derivative instruments
We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify. The effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in OCI in the period of change. Any ineffective portion is recognized in net income in the same financial category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other and interest expense.
Derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period.
The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered or refunded through the tolls charged by us. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles.
Fair value of derivative instruments
The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses current market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives have been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.
Balance sheet presentation of derivative instruments
The balance sheet classification of the fair value of the derivative instruments is as follows:
The effect of derivative instruments on the consolidated statement of income
The following summary does not include hedges of our net investment in foreign operations.
Derivatives in cash flow hedging relationships
The components of the Condensed consolidated statement of OCI related to derivatives in cash flow hedging relationships is as follows:
Credit risk related contingent features of derivative instruments
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 September 30, 2014, the aggregate fair value of all derivative contracts with credit risk related contingent features that were in a net liability position was $13 million (December 31, 2013 – $16 million), with collateral provided in the normal course of business of nil (December 31, 2013 – nil). If the credit risk related contingent features in these agreements had been triggered on September 30, 2014, we would have been required to provide collateral of $13 million (December 31, 2013 – $16 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.
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 September 30, 2014, as required by the Canadian securities regulatory authorities and by the SEC, and concluded t