TransCanada Reports Strong Third Quarter 2016 Financial Results
Strong Operating Performance Reflects Acquisition of Columbia Pipeline Group
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 11/01/16 -- TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada) today announced a net loss attributable to common shares for third quarter 2016 of $135 million or $0.17 per share compared to net income of $402 million or $0.57 per share for the same period in 2015. Third quarter 2016 results included a $656 million after-tax goodwill impairment charge related to our U.S. Northeast Power business. Excluding the net loss on the goodwill impairment and certain other specific items, comparable earnings for third quarter 2016 were $622 million or $0.78 per share compared to $440 million or $0.62 per share for the same period in 2015. TransCanada''s Board of Directors also declared a quarterly dividend of $0.565 per common share for the quarter ending December 31, 2016, equivalent to $2.26 per common share on an annualized basis.
"Excluding specific items, comparable earnings per share for the quarter were significantly higher than last year as a result of the Columbia acquisition and continued solid performance from our large portfolio of high-quality energy infrastructure assets," said Russ Girling, TransCanada''s president and chief executive officer. "Since completing the Columbia transaction, we have made significant progress in integrating its operations with our existing U.S. natural gas pipeline business and are well on track to realize the targeted US$250 million of annualized benefits associated with the acquisition."
On July 1, 2016, TransCanada completed the acquisition of Columbia Pipeline Group, Inc. (Columbia) for US$13 billion. Columbia operates a portfolio of approximately 24,000 km (15,000 miles) of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets.
"The addition of Columbia reinforces our position as one of North America''s leading energy infrastructure companies with an extensive pipeline network that links the continent''s most prolific natural gas supply basins to its most attractive markets," added Girling. "Looking forward, the addition of Columbia''s US$7.7 billion growth program brings our industry-leading portfolio of near-term capital projects to over $25 billion. As these projects progress through the permitting and construction phases and into operation over the balance of the decade, they are expected to generate significant growth in earnings and cash flow and support an expected annual dividend growth rate at the upper end of the Company''s previous expectation of eight to 10 per cent through 2020."
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Net income attributable to common shares decreased by $537 million to a net loss of $135 million or $0.17 per share for the three months ended September 30, 2016 compared to the same period last year. Third quarter 2016 included a $656 million after-tax goodwill impairment charge, an after-tax charge of $67 million related to costs associated with the acquisition of Columbia, a $50 million after-tax charge related to risk management activities, recognition of $28 million of income tax recoveries resulting from a third party sale of Keystone XL project assets, a $9 million after-tax charge related to Keystone XL maintenance and liquidation costs and $3 million of after-tax costs related to the sale of our U.S. Northeast Power business. All of these specific items are excluded from comparable earnings.
Comparable earnings for third quarter 2016 were $622 million or $0.78 per share compared to $440 million or $0.62 per share for the same period in 2015, an increase of $182 million or $0.16 per share. The increase was primarily the net effect of a higher contribution from U.S. Pipelines primarily due to incremental earnings from Columbia following the acquisition on July 1, 2016 and a higher ANR transportation and storage revenue resulting from higher rates effective August 1, 2016; a higher contribution from Mexican pipelines primarily due to earnings from Topolobampo beginning in July 2016; higher interest income and other due to realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income; higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired in February 2016 and higher sales to customers in the PJM market partially offset by lower capacity revenues in New York; higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest partially offset by higher losses from contracting activities; and higher earnings from Canadian Pipelines primarily due to a higher NGTL investment base and incentive earnings from the Canadian Mainline and NGTL. These gains were partially offset by higher interest expense from debt issuances and lower capitalized interest as well as lower earnings from Liquids Pipelines due to the net effect of higher contracted and lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink.
Notable recent developments include:
Corporate:
Natural Gas Pipelines:
Liquids Pipelines:
Energy:
The unaudited interim condensed 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 65 years'' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 90,300 kilometres (56,100 miles), tapping into virtually all major gas supply basins in North America. TransCanada is the continent''s largest provider of gas storage and related services with 664 billion cubic feet of storage capacity. A large independent power producer, TransCanada owns or has interests in over 10,500 megawatts of power generation in Canada and the United States. TransCanada is also the developer and operator of one of North America''s leading liquids pipeline systems that extends over 4,300 kilometres (2,700 miles) connecting growing continental oil supplies to key markets and refineries. TransCanada''s common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com and our blog to learn more, or connect with us on social media and 3BL Media.
Forward Looking Information
This 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 1, 2016 and 2015 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 and available on TransCanada''s website at .
Non-GAAP Measures
This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, comparable distributable cash flow, comparable funds generated from operations, funds generated from operations, comparable earnings per share and comparable distributable cash flow 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 1, 2016.
Additional Information and Where to Find it
In connection with the proposed acquisition of the outstanding common units of CPPL, CPPL will file with the SEC a proxy statement with respect to a special meeting of its unitholders to be convened to approve the transaction. The definitive proxy statement will be mailed to the unitholders of CPPL. INVESTORS ARE URGED TO READ THE PROXY STATEMENT AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION.
Investors will be able to obtain these materials, when they are available, and other documents filed with the SEC free of charge at the SEC''s website, . In addition, copies of the proxy statement, when available, may be obtained free of charge by accessing CPPL''s website at or by writing CPPL at 5151 San Felipe Street, Suite 2500, Houston, Texas 77056, Attention: Corporate Secretary. Investors may also read and copy any reports, statements and other information filed by CPPL with the SEC, at the SEC public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 or visit the SEC''s website for further information on its public reference room.
Participants in the Merger Solicitation
Columbia, an indirect wholly owned subsidiary of the Company, and certain of its directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies in respect of the transaction. Information regarding Columbia''s directors and executive officers is available in its Current Report on Form 8-K filed with the SEC on July 1, 2016. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the proxy statement and other relevant materials to be filed with the SEC when they become available.
Quarterly report to shareholders
Third quarter 2016
Financial highlights
Management''s discussion and analysis
November 1, 2016
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, 2016, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2016 which have been prepared in accordance with U.S. GAAP. On July 1, 2016, we completed the acquisition of Columbia Pipeline Group, Inc. (Columbia). For further information on the acquisition refer to note 4 of the September 30, 2016 unaudited condensed consolidated financial statements. The three and nine months ended September 30, 2016 amounts reflect the results of Columbia post-acquisition from July 1, 2016. Comparative figures do not include Columbia.
This MD&A should also be read in conjunction with our December 31, 2015 audited consolidated financial statements and notes and the MD&A in our 2015 Annual Report.
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 2015 Annual Report. All information is as of November 1, 2016 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 2015 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, except as required 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. Please see the Reconciliation of non-GAAP measures section in this MD&A for a reconciliation of the GAAP measures to the non-GAAP measures.
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. 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 derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally 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 reflective of our underlying operations.
Comparable distributable cash flow
Comparable distributable cash flow is defined as comparable funds generated from operations plus distributions received from operating activities in excess of equity earnings from equity-accounted for investments less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments.
We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. See the Financial condition section for a reconciliation to net cash provided by operations.
Consolidated results - third quarter 2016
Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.
Net income attributable to common shares decreased by $537 million to a net loss of $135 million for the three months ended September 30, 2016 and decreased $736 million for the nine months ended September 30, 2016 compared to the same periods in 2015. The 2016 results included:
The 2015 results included:
Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings.
Comparable earnings increased by $182 million and $180 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 as discussed below in the reconciliation of net income to comparable earnings.
RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
Comparable earnings increased by $182 million for the three months ended September 30, 2016 compared to the same period in 2015. This was primarily the net effect of:
Comparable earnings increased by $180 million for the nine months ended September 30, 2016 compared to the same period in 2015. This was primarily the net effect of:
The stronger U.S. dollar on a year-to-date basis compared to the same period in 2015 positively impacted the translated results of our U.S. and Mexican businesses, along with realized gains on foreign exchange hedges used to manage our exposure, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt.
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 cash flow.
Our capital program as of September 30, 2016, consists of $25 billion of near-term projects and $48 billion of commercially secured medium- to longer-term projects. Amounts presented exclude maintenance capital expenditures, capitalized interest and AFUDC.
All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.
Near-term projects
Medium to longer-term projects
Outlook
Our overall comparable earnings outlook for 2016 will be higher than what was previously included in the 2015 Annual Report due to the net impact of the acquisition of Columbia on July 1, 2016, increased earnings from the remainder of our Natural Gas Pipelines'' assets, changes in our Canadian Power business and lower than expected Liquids and U.S. Power earnings, each of which are addressed within the relevant section of the MD&A.
Consolidated capital spending, equity investments and acquisition
Our expected total capital expenditures as outlined in the 2015 Annual Report remains unchanged.
On April 11, 2016, we announced that we were chosen to build, own and operate the Villa de Reyes pipeline in Mexico. On June 13, 2016, we announced that our joint venture with IEnova, Infraestructura Marina del Golfo (IMG), was chosen to build, own and operate the Sur de Texas natural gas pipeline in Mexico. On July 1, 2016, we acquired Columbia. Although we expect to defer capital expenditures on several of our other natural gas pipelines projects, we expect to spend an estimated additional $1 billion on Columbia capital projects in 2016, approximately $300 million on the Villa de Reyes pipeline project and $200 million on the Sur de Texas pipeline project.
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). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change. In addition, Columbia results are included in the Natural Gas Pipelines segment from its acquisition on July 1, 2016. Comparative periods do not include Columbia.
Natural Gas Pipelines segmented earnings increased by $231 million and $325 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015. Segmented earnings for the three and nine months ended September 30, 2016 included $82 million primarily related to retention and severance expenses incurred within the Natural Gas Pipelines segment resulting from the Columbia acquisition. Year-to-date 2016 segmented earnings also included an additional $4 million pre-tax loss on the sale of TC Offshore. These amounts have been excluded from our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below.
CANADIAN PIPELINES
Net income and comparable EBITDA for our rate-regulated Canadian pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis.
NET INCOME - WHOLLY OWNED CANADIAN PIPELINES
Net income for the Canadian Mainline increased by $5 million for the three months ended September 30, 2016 compared to the same period in 2015 primarily due to higher incentive earnings, partially offset by a lower average investment base and higher carrying charges. Net Income for the Canadian Mainline decreased by $7 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to a lower average investment base and higher carrying charges, partially offset by higher incentive earnings in 2016.
Net income for the NGTL System increased by $11 million and $33 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to a higher average investment base and OM&A incentive earnings recorded in 2016.
U.S. AND INTERNATIONAL PIPELINES
Earnings for our U.S. natural gas pipelines operations, which include Columbia effective July 1, 2016, are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services. Columbia and ANR results are also affected by the contracting and pricing of its storage capacity and incidental commodity sales.
The results for Columbia include our 91.6 per cent effective ownership of Columbia Gas Transmission, Columbia Gulf Transmission, Columbia Midstream and Columbia Energy Ventures through a 84.3 per cent direct ownership and our 46.5 per cent ownership in Columbia Pipeline Partners LP which owns the remaining 15.7 per cent ownership interest in these assets.
Comparable EBITDA for U.S. and International Pipelines increased by US$265 million and US$311 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015. This was the net effect of:
As well, a stronger U.S. dollar on a year-to-date basis in 2016 compared to 2015 had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $77 million and $91 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to the Columbia acquisition on July 1, 2016, a higher investment base on the NGTL System, increased depreciation rates on ANR following the rate settlement, and the effect of a stronger U.S. dollar.
BUSINESS DEVELOPMENT
Business development expenses were lower by $7 million and $23 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to the capitalization of business development activities in 2016 related to the successful Mexico projects, a focus on the Columbia acquisition and decreased business development activity in other areas in 2016.
OUTLOOK
The 2016 earnings outlook for the Canadian regulated and Mexican pipelines remains consistent with what we disclosed in the 2015 Annual Report. We are expecting an increase in 2016 earnings from U.S. Pipelines as a result of the acquisition of Columbia on July 1, 2016 although the impact of the related financing will be reflected in our Corporate segment. Earnings for the other U.S. Pipelines are expected to be slightly higher this year as a result of higher revenues and lower costs.
OPERATING STATISTICS - WHOLLY OWNED PIPELINES
Liquids Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.
Liquids Pipelines segmented earnings decreased by $97 million and $164 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included pre-tax charges related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project as well as unrealized losses from changes in the fair value of derivatives related to our liquids marketing business. These amounts have been excluded from our calculation of comparable EBIT. The remainder of the Liquids Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, 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 decreased by $76 million and $118 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was due to the net effect of lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink, partially offset by higher contracted volumes on Keystone Pipeline.
BUSINESS DEVELOPMENT AND OTHER
Business development and other, which primarily includes business development activity and our marketing business, decreased by $5 million and $9 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was the effect of lower business development spending and a growing contribution from the marketing business.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $4 million and $12 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.
OUTLOOK
Excluding specified items, our 2016 earnings are expected to be lower than our 2015 earnings due to lower uncontracted volumes and market conditions related to the lower crude oil price environment.
Following our Keystone XL impairment charge in 2015, expenditures on the project for the maintenance and liquidation of project assets are being expensed pending further advancement of this project and are expected to be approximately $55 million before tax ($36 million after tax) in 2016. These costs will continue to be excluded from comparable earnings.
Energy
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.
Energy segmented earnings decreased by $1,069 million and $1,284 million to segmented losses of $825 million and $569 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT:
The variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time; however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impacts of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations.
Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast Power business, we were required to discontinue hedge accounting for certain cash flow hedges. This, along with the increased volume of our risk management activities associated with the expansion of our customer base in the PJM market, has contributed to higher volatility in U.S. Power risk management activities.
The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.
Comparable EBITDA for Energy increased by $79 million for the three months ended September 30, 2016 compared to the same period in 2015 due to the net effect of:
Comparable EBITDA for Energy decreased by $6 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to the net effect of:
CANADIAN POWER
Western and Eastern Power
Sales volumes and plant availability
Includes our share of volumes from our equity investments.
Western Power
Comparable EBITDA for Western Power increased by $2 million for the three months ended September 30, 2016 compared to the same period in 2015 mainly due to higher realized prices on generated volumes offset by lower earnings following the termination of the PPAs.
Comparable EBITDA for Western Power decreased by $24 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to lower realized power prices and termination of the PPAs.
Results from the Alberta PPAs are included up to March 7, 2016 when we sent notice to the Balancing Pool to terminate the PPAs for the Sundance A, Sundance B and Sheerness facilities. Comparable income from equity investments included earnings from the ASTC Power Partnership which held our 50 per cent ownership in the Sundance B PPA. See the Recent developments section for more information on the PPA terminations.
Average spot market power prices in Alberta decreased 31 per cent from $26/MWh to $18/MWh for the three months ended September 30, 2016 and decreased 54 per cent from $37/MWh to $17/MWh for the nine months ended September 30, 2016 compared to the same periods in 2015. The Alberta power market remained well-supplied and power consumption was down due to a weak economy. 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.
One hundred per cent of Western Power sales volumes were sold under contract in third quarter 2016 compared to 61 per cent in third quarter 2015.
Depreciation and amortization decreased by $12 million and $24 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 following the termination of the PPAs.
We continue to expect Western Power 2016 earnings to be consistent with 2015 earnings. Although Alberta power prices are expected to remain low in the remaining months of 2016, the natural gas-fired cogeneration assets are expected to perform well in the lower natural gas price environment and the March 2016 decision to exercise the right to terminate the PPAs is expected to result in savings from the otherwise increased costs related to carbon emissions.
Eastern Power
Comparable EBITDA for Eastern Power decreased by $4 million and $36 million for the three and nine months ended September 30, 2016 compared to the same period in 2015 mainly due to lower contractual earnings at Becancour, and lower earnings on the sale of unused natural gas transportation for the nine months ended September 30, 2016 compared to the same period in 2015.
Our 2016 earnings outlook provided in the 2015 Annual Report will be modestly lower as a result of a delay in the implementation of amendments to the Becancour electricity supply contract. See the Recent developments section for more information about this agreement.
BRUCE POWER
Results reflect our proportionate share. Bruce A and B were merged in December 2015 and comparative information for 2015 is reported on a combined basis to reflect the merged entity.
Equity income from Bruce Power increased by $19 million and $8 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to lower depreciation as a result of the Bruce Power facility''s operating life extension and our increased ownership interest. These increases were partially offset by higher losses from contracting activities in the three months ended September 30, 2016 and lower volumes and higher operating costs from higher planned outage days for the nine months ended September 30, 2016 compared to the same periods in 2015.
In December 2015, Bruce Power entered into an agreement with the IESO to extend the operating life of the Bruce Power facility to 2064. As part of this agreement, Bruce Power began receiving a uniform price of $65.73 per MWh for all units, which includes certain flow-through items such as fuel and lease expenses recovery. Over time, the price will be subject to adjustments for the return of and on capital invested under the Asset Management and Major Component Replacement capital programs, along with various other pricing adjustments that allow for a better matching of revenues and costs over the long term.
Prior to the amended agreement with the IESO, all of the output from Bruce units 1 to 4 was sold at a fixed price/MWh which was adjusted annually on April 1 for inflation and other provisions under the contract.
Prior to the amended agreement with the IESO, all output from Bruce units 5 to 8 was subject to a floor price adjusted annually for inflation on April 1.
Bruce Power also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.
The contract with the IESO provides for payment if the IESO reduces Bruce Power''s generation to balance the supply of and demand for electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered deemed generation for which Bruce Power is paid the contract price.
During second quarter 2016, Bruce units 1 to 4 were removed from service for approximately three weeks to facilitate a station containment outage. The station containment outage involved inspecting and maintaining key safety systems including containment structures and is required to be completed approximately once every decade. Additional planned maintenance was completed on unit 3 in third quarter 2016. Planned maintenance on unit 7 began in third quarter 2016 and is scheduled to be completed in fourth quarter 2016. The overall average plant availability percentage in 2016 is expected to be in the low 80s.
We expect 2016 equity income from Bruce Power to be slightly higher than our 2016 Outlook in the 2015 Annual Report primarily due to strong results year-to-date.
U.S. POWER
Sales volumes and plant availability
U.S. Power - other information
Comparable EBITDA for U.S. Power increased US$24 million for the three months ended September 30, 2016 compared to the same period in 2015 primarily due to the net effect of:
Comparable EBITDA for U.S. Power decreased US$12 million for the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to the net effect of:
Higher sales to wholesale utility customers in the PJM market resulted in higher earnings for the three months ended September 30, 2016 compared to the same period in 2015 as we continue to expand our customer base in the PJM market. However, significantly lower realized power prices and mild winter weather have resulted in lower margins in our wholesale business in both the PJM and New England markets for the nine months ended September 30, 2016 compared to the same period in 2015, the impact of which was primarily seen in the first quarter results.
Wholesale electricity prices in New York and New England were slightly higher for the three months ended September 30, 2016 and significantly lower for the nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to unseasonably warm weather in first quarter 2016. In New England, spot power prices for the three and nine months ended September 30, 2016 were 10 per cent higher and 38 per cent lower compared to the same periods in 2015. In New York City, spot power prices for the three and nine months ended September 30, 2016 were six per cent higher and 34 per cent lower compared to the same periods in 2015.
Average New York Zone J spot capacity prices were approximately 20 per cent and 23 per cent lower for the three and nine months ended September 30, 2016 compared to the same periods in 2015. The decrease in spot prices and the offsetting impact of hedging activities resulted in lower realized capacity prices in New York. This was primarily due to an increase in demonstrated capability from existing resources in New York City''s Zone J market. The impact of lower capacity prices in New York was partially offset by capacity revenues earned by our Ironwood power plant acquired in February 2016.
Capacity revenues were also negatively impacted by an outage at Unit 30 from September 2014 to May 2015 at Ravenswood. The calculation used by the NYISO to determine the capacity volume for which a generator is compensated utilizes a rolling average forced outage rate. As a result of this methodology, outages impact capacity volumes and associated revenues on a lagged basis. Accordingly, capacity revenues for the three and nine months ended September 30, 2016 were negatively impacted compared to the same periods in 2015. The outage continues to be included in the rolling average forced outage rate. Insurance recoveries, net of deductibles, for this event have been received and are being recognized in capacity revenues to offset amounts lost during the periods impacted by the lower forced outage rate. As a result of these insurance recoveries, the Unit 30 unplanned outage has not had a significant impact on our earnings although the recording of earnings has not coincided exactly with lost revenues due to timing of the insurance proceeds. In addition, insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008 were received in June 2016 and a portion of the proceeds were recognized in Power Revenue.
Physical generation volumes in 2016 were higher compared to the same period in 2015 due to our acquisition of the Ironwood power plant and higher generation at our Ravenswood facilities. Physical purchased volumes sold to wholesale, commercial and industrial customers were higher for the three and nine month months ended September 30, 2016 than the same periods in 2015 as we have expanded our customer base in the PJM and New England markets.
As at September 30, 2016, approximately 1,500 GWh, or 43 per cent, of U.S. Power''s planned generation was contracted for the remainder of 2016 and 3,900 GWh, or 30 per cent, for 2017. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage and plant availability.
U.S. Power results for 2016 are not expected to be significantly impacted by the announced monetization of the U.S. Northeast Power business as these transactions are not expected to close until the first half of 2017. See the Recent developments section for more information. Nevertheless, operating results for the full year in 2016 are expected to be lower than the Outlook in our 2015 Annual Report due to lower commodity prices experienced in the first half of 2016.
NATURAL GAS STORAGE AND OTHER
Comparable EBITDA increased by $21 million and $31 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to increased storage revenues as a result of higher realized natural gas storage price spreads.
The full year 2016 results are expected to be higher compared to 2015 due to the lack of seasonal winter weather conditions, excess natural gas supply and the resulting increase in natural gas storage price spreads which have provided the opportunity to hedge available storage capacity at higher values than originally expected in the Outlook in our 2015 Annual Report.
Corporate
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.
Corporate segmented losses in 2016 increased by $6 million and $61 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT:
Interest expense
Comparable interest expense increased by $175 million and $351 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 due to the net effect of:
Interest income and other
Comparable interest income and other increased by $80 million and $277 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 due to the net effect of:
Income tax expense
Comparable income tax expense increased by $25 million and decreased by $38 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was mainly the result of changes in the proportion of income earned between Canadian and foreign jurisdictions and lower flow-through taxes in 2016 on Canadian regulated pipelines.
Net income attributable to non-controlling interests
Net income attributable to non-controlling interests increased by $6 million and $39 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included a $3 million charge related to the non-controlling interest portion of retention and severance expenses resulting from the Columbia acquisition.
Comparable net income attributable to non-controlling interests increased by $9 million and $42 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to the acquisition of Columbia which included a non-controlling interest in Columbia Pipeline Partners LP. In addition, the sale of our 30 per cent direct interest in GTN in April 2015 and 49.9 per cent direct interest in PNGTS in January 2016 to TC PipeLines, LP along with the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP increased net income attributable to non-controlling interests year-over-year.
Preferred share dividends
Preferred share dividends increased by $4 million and $6 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to preferred shares issuances in 2016 and 2015 offset by lower dividend rates on certain series.
Recent developments
ACQUISITION OF COLUMBIA PIPELINE GROUP, INC.
Acquisition
On July 1, 2016, we closed the acquisition of Columbia valued at US$13 billion comprised of a purchase price of approximately US$10.3 billion and Columbia debt of approximately US$2.7 billion. The acquisition was financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on bridge term loan credit facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, following the closing of the acquisition, were exchanged into 96.6 million TransCanada common shares. See Financial condition section for additional information on the bridge term loan credit facilities and the subscription receipts.
Columbia operates a portfolio of approximately 24,000 km (15,000 miles) of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets. We acquired Columbia to expand our natural gas business in the U.S. market, positioning ourselves for additional long-term growth opportunities. The acquisition also includes a large portfolio of new capital growth projects which includes seven pipeline expansion projects designed to transport growing supply from the Marcellus / Utica production basins to markets as well as a scheduled program for modernization of existing infrastructure out to 2020 to ensure the continuation of a safe, reliable and efficient system. We are currently executing plans to ensure an effective integration of Columbia into the TransCanada organization. We remain on track to realizing our $250 million of annual cost, revenue and financing benefits.
The following table summarizes the acquisition related costs for Columbia that have been excluded from comparable earnings for the three and nine months ended September 30, 2016.
Monetization of U.S. Northeast Power business
We currently expect to realize approximately US$3.7 billion from the monetization of our U.S. Northeast Power business. This includes the November 1, 2016 announced sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors for US$2.2 billion and TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC for US$1.065 billion, with the remainder attributed to the marketing business which is expected to be realized going forward. These two sale transactions are expected to close in the first half of 2017 subject to certain regulatory and other approvals and will include closing adjustments. These sales are expected to result in an approximate $1.1 billion after-tax net loss which is comprised of a $656 million after-tax goodwill impairment charge recorded at September 30, 2016, an approximate $863 million after-tax net loss on the sale of the thermal and wind package to be recorded in fourth quarter 2016 and an approximate $443 million after-tax gain on the sale of the hydro assets to be recorded upon close of that transaction. Proceeds from these sales and future realization of value of the marketing business will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to partially finance the Columbia acquisition earlier this year.
Minority interest in Mexican pipelines
As part of the Columbia acquisition financing plan, we previously disclosed our intention to monetize a minority interest in our Mexico natural gas pipeline business. On November 1, 2016, we announced a decision to maintain our full ownership interest in a growing portfolio of natural gas pipeline assets in Mexico rather than sell a minority interest in six of these pipelines, which is consistent with maintaining a simple corporate structure. We currently own and operate the Tamazunchale and Guadalajara pipelines and are investing US$3.8 billion to develop and complete construction of four additional pipelines plus fund our interest in the Sur de Texas project, all of which will serve growing natural gas demand in Mexico. All projects are expected to be in-service by the end of 2018 and are underpinned by 25-year take-or-pay contracts with the CFE. Once completed, we expect our Mexican natural gas pipeline assets to be accretive to earnings per share and generate approximately US$575 million of annual EBITDA, up from US$181 million in 2015.
In connection with this decision, we also entered into an agreement with a group of underwriters to proceed with a common equity offering concurrent with the release of these financial results. See Corporate recent developments for more information.
NATURAL GAS PIPELINES
Canadian Regulated Pipelines
NGTL System
On October 31, 2016, the Government of Canada approved our $1.3 billion NGTL 2017 Facilities Application. In addition, on October 6, 2016, the NEB recommended to the government approval of the $0.4 billion Towerbirch Project. This project consists of a 55 km (34 miles) pipeline loop and a 32 km (20 miles) pipeline extension of the NGTL System in northwest Alberta and northeast B.C. Of NGTL''s $5.4 billion near-term capital program we have received approvals for $4.0 billion, while $0.5 billion has been filed and is awaiting approval. Approximately $0.9 billion is expected to filed with regulators in the future.
We continue to work closely with our shippers to ensure that new proposed facilities meet our shippers and market demands. In second quarter 2016, we added new long term delivery contracts on the NGTL System to meet demand in the Pacific Northwest and California which will require the construction of $135 million of new facilities (the Sundre Crossover Project) that were not previously included in our 2018 Facilities program. The open season process supporting the development of these new contracts identified further demand for service to this market that we are currently assessing.
In second quarter 2016, in response to cancellations or deferrals of our certain customer projects, contract non-renewals, and contract transfers, we re-evaluated planned facility requirements to meet future aggregate system service requirements and made changes in the spending profile of our programs to match revised in-service dates. The projected expansion capital spend for the NGTL System remains at approximately $7.3 billion, including the new Sundre Crossover Project, the North Montney and Merrick pipelines and the cancellation of a $66 million project. We have deferred approximately $225 million of spending for facilities in the 2016/17 Facilities program with revised service dates of 2018 through 2020 as well as $210 million of spending for facilities in the 2018 Facilities program with revised service dates of 2019 and 2020.
North Montney Mainline
In March 2016, we filed a request with the NEB for a one year extension to the June 10, 2016 sunset clause in the North Montney Mainline (NMML) project Certificate of Public Convenience and Necessity (CPCN). On September 15, 2016, the NEB approved the sunset clause extension to June 10, 2017. The extension continues to be subject to the condition that construction shall not begin until a positive Final Investment Decision (FID) has been made on the Pacific Northwest LNG (PNW LNG) Project. NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the NMML facilities, however, the in-service date will be finalized once a FID has been made.
2016-2017 NGTL Revenue Requirement Settlement
In April 2016, the NEB approved the NGTL revenue requirement settlement application that was filed in December 2015, subject to certain reporting requirements that were subsequently met and approved by the NEB. The settlement includes a ROE of 10.1 per cent on a deemed common equity of 40 per cent, continuation of 2015 depreciation rates, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration cost amount and flow-through treatment of all other costs.
Canadian Mainline Tolling Option Open Season
On October 13, 2016, we launched an open season for the Canadian Mainline, seeking binding commitments on our new long-term, fixed-price proposal to transport WCSB supply from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The contract term for this service is ten years with tolls ranging from $0.75/GJ to $0.82/GJ depending on the shippers'' contract volume commitments. Early termination rights are provided and can be exercised following the initial five years of service upon payment of a premium fee. Subject to a successful open season that closes November 10, 2016, and to NEB regulatory approval, the new service is targeted to begin November 1, 2017.
U.S. Pipelines
Columbia Capital Projects
The July 1, 2016 acquisition of Columbia included a capital expansion program that was underway for new facilities planned to be in service in 2017 and 2018 as well as modernization programs for existing assets to be completed through 2020. The large capital expansion program consists of US$7.4 billion related to our regulated pipeline business and US$0.3 billion related to our midstream business. The following summarizes the key capital projects for this new set of assets that are now part of the our overall Natural Gas Pipelines footprint in North America.
Leach XPress
This Columbia Gas Transmission (TCO) project is designed to transport up to 1.5 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with the Columbia Gulf System (CGT). The project consists of 219 km (136 miles) of 36-inch greenfield pipe, 39 km (24 miles) of 36-inch loop, three km (two miles) of 30-inch greenfield pipe, 82.8 MW (111,000 hp) of greenfield compression and 24.6 MW (33,000 hp) of brownfield compression. We expect the project, with an estimated capital investment of US$1.4 billion, to be in service in fourth quarter 2017. The FERC 7© application was filed in June 2015 and the Final Environmental Impact Statement (FEIS) was received September 1, 2016.
Rayne XPress
This CGT project is designed to transport up to 1.1 Bcf/d of southwest Marcellus and Utica production associated with the Leach XPress expansion and an interconnect with the Texas Eastern System (TETCO) to various delivery points on the CGT system and Gulf Coast. The project consists of bi-directional compressor station modifications along the CGT system, 38.8 MW (52,000 hp) of greenfield compression, 20.1 MW (27,000 hp) of replacement compression and six km (four miles) of 30-inch pipe replacement. We expect the project, with an estimated capital investment of US$420 million, to be in service in fourth quarter 2017. The FERC 7© application was filed in July 2015 and the FEIS was received September 1, 2016.
Mountaineer XPress
This TCO project is designed to transport up to 2.7 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with the CGT system. The project consists of 264 km (164 miles) of 36-inch greenfield pipeline, ten km (six miles) of 24-inch lateral pipeline, 0.6 km (0.4 miles) of 30-inch replacement pipeline, 114.1 MW (153,000 hp) of greenfield compression and 55.9 MW (75,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$2 billion, to be in service in fourth quarter 2018. The FERC 7© application was filed in April 2016.
Gulf XPress
This CGT project is designed to transport up to 0.9 Bcf/d associated with the Mountaineer XPress expansion to various delivery points on the CGT system and Gulf Coast. The project consists of adding seven greenfield midpoint compressor stations along the CGT System route totaling 182.7 MW (254,000 hp). We expect this project, with an estimated capital investment of US$0.7 billion, to be placed in service in fourth quarter 2018. The FERC 7© application was filed in April 2016.
Cameron Access Project
This CGT project is designed to transport up to 0.8 Bcf/d of gas supply to the Cameron LNG export terminal in Louisiana. The project consists of 44 km (27 miles) of 36-inch greenfield pipeline, 11 km (seven miles) of 30-inch looping and 9.7 MW (13,000 hp) of greenfield compression. We expect this project, with an estimated capital investment of US$300 million, to be in service in first quarter 2018. The FERC certificate was received in September 2015.
WB XPress
This TCO project is designed to transport up to 1.3 Bcf/d of Marcellus gas supply westbound (0.8 Bcf/d) to the Gulf Coast via an interconnect with the Tennessee Gas Pipeline, and eastbound (0.5 Bcf/d) to Mid-Atlantic markets, WGL Midstream and Transco interconnects. The project consists of 47 km (29 miles) of various diameter pipeline, 338 km (210 miles) of restoring and uprating maximum operating pressure of existing pipeline, 29.8 MW (40,000 hp) of greenfield compression and 99.9 MW (134,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$0.9 billion, to have a Western build in service in the beginning of second quarter 2018 and an Eastern build in service in fourth quarter 2018. The FERC 7© application for both segments was filed in December 2015.
Modernization I & II
TCO and its customers have entered into a settlement arrangement, approved by FERC, which provides recovery and return on investment to modernize its system, improve system integrity and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Modernization I has been approved for up to US$0.6 billion of work yet to be completed in 2016 through 2017. Modernization II has been approved for up to US$1.1 billion of work to be completed in 2018 through 2020. As per terms of the arrangements, facilities in service by October 31 collect revenues effective February 1 of the following year.
Columbia Midstream - Gibraltar Pipeline Project
We expect to invest US$260 million to construct an approximate 1 MMDth/d dry gas header pipeline in southwest Pennsylvania to be completed in multiple phases with an initial in-service date in fourth quarter 2016 and a final in-service date in fourth quarter 2017.
ANR Section 4 Rate Case Settlement
ANR reached a settlement with its shippers effective August 1, 2016 and filed the final, unopposed settlement agreement with the FERC for approval on September 16, 2016. Transmission reservation rates will increase by 34.8 per cent and storage rates will remain the same for contracts one to three years in length, while increasing slightly for contracts of less than one year and decreasing slightly for contracts more than three years in duration. There is a moratorium on any further rate changes until August 1, 2019. ANR may file for new rates after that date if it has spent more than US$0.8 billion in capital additions, but must file for new rates no later than an effective date of August 1, 2022.
Columbia Pipeline Partners, LP
On November 1, 2016, we announced that we have entered into an agreement and plan of merger through which our wholly-owned subsidiary, Columbia Pipeline Group, Inc, has agreed to acquire, for cash, all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. Common unitholders will also continue to receive regular quarterly distributions of US$0.1975 per common unit including a pro-rated distribution for any partial period to the closing date. The transaction is expected to close in first quarter 2017 subject to receipt of CPPL unitholder approval and customary closing conditions, and is expected to be accretive to earnings per share and simplify our corporate structure. There will be no gain or loss recorded on closing this transaction as CPPL is a consolidated subsidiary.
Mexico
Topolobampo Pipeline
The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a capacity of 670 MMcf/d and a cost of US$1 billion that will deliver natural gas from interconnections with third party pipelines to Topolobampo, Sinaloa and into the Mazatlan pipeline. Construction of the pipeline is supported by a 25-year natural gas Transportation Service Agreement (TSA) for 670 MMcf/d with the CFE. The physical in-service date is expected to be delayed into 2017 due to right-of-way acquisition delays. Under the terms of the TSA, this delay is recognized as a force majeure event with provisions allowing for the collection of revenue as per the original TSA service commencement date of July 2016.
Mazatlan Pipeline
The Mazatlan project is a 413 km (257 miles), 24-inch diameter pipeline running from El Oro to Mazatlan within the state of Sinaloa with an estimated cost of US$0.4 billion and is supported by 25-year contract with the CFE. Construction of the pipeline is supported by a 25-year natural gas TSA for 200 MMcf/d with the CFE. Physical construction
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