Mr. Russ Girling reports

TRANSCANADA REPORTS STRONG SECOND QUARTER 2015 FINANCIAL RESULTS

TransCanada Corp. had net income attributable to common shares for second quarter 2015 of $429-million or 60 cents per share compared with $416-million or 59 cents per share for the same period in 2014. Comparable earnings for second quarter 2015 were $397-million or 56 cents per share compared with $332-million or 47 cents per share for the same period last year. TransCanada's board of directors also declared a quarterly dividend of 52 cents per common share for the quarter ending Sept. 30, 2015, equivalent to $2.08 per common share on an annualized basis.

"Our three core businesses produced another solid quarter of financial results demonstrating the resiliency of our high-quality asset base in challenging market conditions," said Russ Girling, TransCanada's president and chief executive officer. "Comparable earnings and funds generated from operations increased 20 and 16 per cent, respectively, compared with the same period last year highlighting the strong foundation that will allow us to continue to grow the dividend at an annual rate of 8 to 10 per cent through 2017 and fund our industry-leading $46-billion capital program."

Over the past several months, the company advanced key components of its growth plans which included more than $13-billion in proposed natural gas pipeline projects to support the emerging liquefied natural gas (LNG) industry on the British Columbia coast. The company's Prince Rupert gas transmission (PRGT) project reached an important milestone with a positive final investment decision (FID), subject to two conditions, from Pacific NorthWest LNG (PNW LNG). The company also received the majority of the facilities permits for both its PRGT and Coastal GasLink projects which positions it to be ready to commence construction, pending an FID from the respective project sponsors. PRGT and Coastal GasLink also continued their engagement with aboriginal groups along the pipeline routes and signed several project agreements with first nation communities.

The company also continues to advance the balance of its $46-billion portfolio of commercially secured projects as well as numerous other growth initiatives. These projects are expected to result in significant growth in earnings, cash flow and dividends through the end of the decade. With its high-quality asset base and financial strength, the company remains well positioned to create long-term shareholder value throughout various market conditions.

Highlights (all financial figures are unaudited and in Canadian dollars unless noted otherwise)

Second quarter financial results

• Net income attributable to common shares of $429-million or 60 cents per share;
• Comparable earnings of $397-million or 56 cents per share;
• Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.4-billion;
• Funds generated from operations of $1.1-billion;
• Declared a quarterly dividend of 52 cents per common share for the quarter ending Sept. 30, 2015;
• PRGT reaching a significant milestone when PNW LNG announced a positive FID, subject to two conditions, for its proposed liquefaction and export facility on the West Coast of B.C.;
• Received a majority of the pipeline and facilities permits for PRGT and Coastal GasLink;
• Received regulatory approval for the $1.7-billion North Montney mainline project;
• Continued to advance its master limited partnership strategy with the drop down of the remaining 30-per-cent interest in Gas Transmission Northwest LLC (GTN) for $457-million (U.S.);
• Completed over $1.5-billion of financing with the issuance of junior subordinated and medium-term notes.

Net income attributable to common shares increased by $13-million to $429-million or 60 cents per share for the three months ended June 30, 2015, compared with the same period last year. Second quarter 2015 included a $34-million income tax expense adjustment due to an increase in the Alberta corporate income tax rate and an $8-million aftertax restructuring charge related to changes to the company's major projects group. Second quarter 2014 included a $99-million aftertax gain from the sale of Cancarb and a $31-million aftertax loss from the termination of a natural gas storage contract. Both periods included unrealized gains and losses from changes in risk management activities. All of these specific items are excluded from comparable earnings.

Comparable earnings for second quarter 2015 were $397-million or 56 cents per share compared with $332-million or 47 cents per share for the same period in 2014. Higher earnings from the Canadian mainline, NGTL system, Keystone, Bruce Power and Eastern Power were partially offset by lower contributions from U.S. Power and Western Power.

Notable recent developments in natural gas pipelines, liquids pipelines, energy and corporate include:

Natural gas pipelines

NGTL system expansions

The NGTL system has approximately $6.8-billion of new supply and demand facilities currently under development. In second quarter 2015, the company continued to advance several of these capital expansion projects and plans to file additional facilities applications for this program through the remainder of 2015. The company has received additional requests for firm receipt service that it anticipates will increase the overall capital spend on the NGTL system beyond the previously announced program and continue to work with its customers to best match their requirements for 2016, 2017 and 2018 in-service dates.

On April 15, 2015, the National Energy Board (NEB) issued its report recommending the federal government approve the NGTL system's $1.7-billion North Montney mainline project which will provide substantial new capacity on the NGTL system to meet the transportation requirements associated with rapidly increasing development of natural gas resources in the Montney supply basin in northeastern B.C. The project will connect Montney and other Western Canada sedimentary basin supply to both existing and new natural gas markets, notably emerging markets for LNG.

The North Montney mainline project will consist of two large-diameter, 42-inch pipeline sections, Aitken Creek and Kahta, totalling approximately 301 kilometres (187 miles) in length, and associated metering facilities, valve sites and compression facilities. The project will also include an interconnection with the company's proposed PRGT project to provide natural gas supply to the proposed PNW LNG liquefaction and export facility near Prince Rupert, B.C. NGTL currently expects to have the Aitken Creek section in service in late 2016, and the Kahta section in service in 2017.

The federal government approved the recommendations of the report from the NEB, and on June 11, 2015, the NEB issued a certificate of public convenience and necessity to proceed with the project, subject to certain terms and conditions. Under one of these conditions, construction on the North Montney mainline project can only begin after a confirmation of FID has been made on the proposed PNW LNG project and the company is proceeding with construction on PRGT.

Canadian mainline

On March 31, 2015, the company submitted a compliance toll filing in response to direction from the NEB's RH-001-2014 decision issued in November, 2014. On June 12, 2015, the NEB approved the applied-for-compliance tolls, as filed. These final tolls became effective on July 1, 2015, which allowed, among other things, the recording of incentive earnings as approved by the NEB.

On June 2, 2015, the NEB approved construction of the King's North connection project to expand gas transmission capacity in the Greater Toronto Area and provide shippers with the flexibility to source growing supplies of Marcellus gas from the U.S. Northeast. The project is expected to cost approximately $220-million and is anticipated to be in service by third quarter 2016.

PRGT

In second quarter 2015, the company received six of the 11 pipeline and facilities permits from the B.C. Oil and Gas Commission needed to build and operate PRGT. The company anticipates decisions on the remaining B.C. OGC permits in third quarter 2015. PRGT is a 900 km (559-mile) natural gas pipeline that will deliver gas from the North Montney producing region near Fort St. John, B.C., at an interconnect on the NGTL system to the proposed PNW LNG facility near Prince Rupert, B.C.

The company continued its engagement with aboriginal groups along the pipeline route and during the quarter announced the signing of project agreements with Gitanyow First Nation, Kitselas First Nation, Lake Babine Nation, Doig River First Nation, Halfway River First Nation and Yekooche First Nation.

On June 11, 2015, PNW LNG announced a positive FID for the proposed liquefaction and export facility, subject to two conditions. The first condition is approval by the Legislative Assembly of B.C. of a project development agreement between PNW LNG and the Province of B.C. This condition was satisfied in mid-July, 2015. The second condition is a positive regulatory decision on PNW LNG's environmental assessment by the government of Canada.

Subject to successful completion of the regulatory process for PRGT, the company remains on target to begin construction following confirmation of an FID by PNW LNG. The in-service date for PRGT is estimated to be 2020 but will be aligned with PNW LNG's liquefaction facility timeline.

Coastal GasLink

The company has received eight of 10 pipeline and facilities permits from the B.C. OGC and anticipates receiving the remaining two permits in third quarter 2015. The company is continuing its engagement with aboriginal groups along the pipeline route and on June 29, 2015, the company announced the signing of project agreements with Wet'suwet'en First Nation, Skin Tyee Nation, Nee-Tahi-Buhn Band, Yekooche First Nation, Doig River First Nation and Halfway River First Nation, all of Northern B.C.

Coastal GasLink is a 670 km (416-mile) natural gas pipeline that will deliver gas from the Montney producing region at an expected interconnect on the NGTL system near Dawson Creek, B.C., to LNG Canada's proposed LNG facility near Kitimat, B.C. The project is subject to regulatory approvals and a positive FID.

GTN drop down

On April 1, 2015, the company closed the sale of its remaining 30-per-cent interest in GTN to its master limited partnership, TC PipeLines LP. The $457-million (U.S.) sale, which included a $11-million (U.S.) purchase price adjustment, comprised $264-million (U.S.) in cash, the assumption of $98-million (U.S.) in proportional GTN debt and the issuance of $95-million (U.S.) of new Class B units to TransCanada. The Class B units entitle the company to a cash distribution based on 30 per cent of GTN's annual cash distribution after certain thresholds are achieved, namely 100 per cent of distributions above $20-million (U.S.) in the first five years and 25 per cent of distributions above $20-million (U.S.) in subsequent years.

The drop down of the remaining interest in GTN is part of a systematic series of transactions to sell the remainder of TransCanada's U.S. natural gas pipeline assets to the partnership to help the company finance its capital program.

At June 30, 2015, the company held a 28.2-per-cent interest in the partnership.

Liquids pipelines

Energy East pipeline

On April 2, 2015, the company announced that the marine and associated tank terminal in Cacouna, Que., will not be built as a result of the recommended reclassification of beluga whales as an endangered species. The company is currently evaluating other options and amendments to the project are expected to be submitted to the NEB in fourth quarter 2015. The NEB has continued to process the application in the interim.

The alteration to the project scope and further refinement of the project schedule is expected to result in an in-service date of 2020. The original $12-billion cost estimate is expected to increase due to further scope refinement as the company consults with stakeholders and escalation of construction costs as the project schedule is refined.

Binding long-term contracts of approximately one million barrels per day (bbl/d) for the 1.1 million bbl/d pipeline have been secured and discussions with shippers continue.

Keystone pipeline system

In July, 2015, the Keystone pipeline system marked the safe delivery of the one billionth barrel of Canadian and U.S. crude oil and celebrated the five-year anniversary of the official start of oil deliveries for the 4,247 km (2,639-mile) cross-border pipeline from Hardisty, Alta., to markets in the American Midwest and in 2014 to the U.S. Gulf Coast.

Construction continues on the 77 km (48-mile) Houston lateral pipeline and tank terminal which will extend the Keystone pipeline system to Houston, Tex., refineries. The terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are expected to be completed in fourth quarter 2015.

On April 14, 2015, the company, along with Magellan Midstream Partners LP (Magellan), announced a joint development agreement to connect its Houston terminal to Magellan's East Houston terminal. The company will own 50 per cent of this $50-million (U.S.) pipeline project which will enhance connections to the Houston market for its Keystone pipeline system. Subject to definitive agreements and receipt of necessary permits and approvals, the pipeline is expected to be operational in late 2016.

Keystone XL

In January, 2015, the Department of State (DOS) reinitiated the national interest review and requested the eight federal agencies with a role in the review to complete their consideration of whether Keystone XL serves the national interest. All of the agency comments were submitted.

On Feb. 12, 2015, Nebraska county courts granted temporary injunctions that were negotiated between the company and landowners' counsel which prevent Keystone from proceeding with condemnation cases until the underlying constitutional litigation is resolved. A renewed challenge to the constitutionality of the statute under which the governor approved the reroute in the state is pending in a Nebraska district court.

On June 29, 2015, TransCanada sent a letter to the DOS with additional evidence demonstrating that Canada is taking strong steps toward managing carbon emissions.

The South Dakota Public Utility Commission has scheduled a hearing in third quarter 2015 on the company's request to certify its existing permit authority in that state.

The estimated capital cost for Keystone XL is expected to be approximately $8-billion (U.S.). As of June 30, 2015, the company has invested $2.4-billion (U.S.) in the project and has also capitalized interest in the amount of $400-million (U.S.).

Heartland pipeline and TC terminals

On May 7, 2015, the Alberta Energy Regulator issued a permit for construction of the Heartland pipeline. The in-service date of the project will be aligned to meet market requirements for incremental capacity between the Heartland region near Edmonton, Alta., and Hardisty, Alta.

Crude oil prices continue to remain low, prompting many producers to cut capital spending and delay oil sands projects in Western Canada. In its 2015 crude oil forecast, markets and transportation report, the Canadian Association of Petroleum Producers estimated Western Canada sedimentary basin crude oil production will continue to grow but at a slower pace than previously anticipated. The company's liquids pipelines projects are supported by long-term contracts. However, with the slowing in growth of crude oil production, the company's intra-Alberta projects may experience a similar slowing pace of growth to align with customer requirements.

Energy

Alberta greenhouse gas (GHG) emissions

On June 25, 2015, the Alberta government announced a renewal and change to the specified gas emitters regulations (SGER) in Alberta. Since 2007 under the SGER, established industrial facilities with GHG emissions above a certain threshold are required to reduce their emissions by 12 per cent below an average intensity baseline and a carbon levy of $15 per tonne is placed on emissions above this target. The changed regulations include an increase in the emissions reductions target to 15 per cent in 2016 and 20 per cent in 2017, along with an increase in the carbon levy to $20 per tonne in 2016 and $30 per tonne in 2017. The company's Sundance and Sheerness power purchase arrangements are subject to this regulation. The company's significant inventory of carbon offset credits are expected to mitigate the majority of these increased costs. The remaining compliance costs are expected to be recovered through increased market pricing and contract flow-through provisions.

Ravenswood

In late May, 2015, the 972-megawatt unit 30 at the Ravenswood generating station returned to service after a September, 2014, unplanned outage which resulted from a problem with the generator associated with the high-pressure turbine.

Corporate

The company's board of directors declared a quarterly dividend of 52 cents per share for the quarter ending Sept. 30, 2015, on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.08 per common share on an annualized basis.

Financing activities

In May, 2015, a newly formed financing trust issued $750-million (U.S.) of 60-year junior subordinated trust notes to third party investors with a fixed interest rate of 5.625 per cent for the first 10 years converting to a floating rate thereafter. The notes are callable at par beginning 10 years following their issuance. All of the proceeds of the issuance by the trust were loaned to the company in $750-million (U.S.) junior subordinated notes at a rate of 5.875 per cent which includes a 0.25-per-cent administration charge. On a subordinated basis, the obligations of the trust are guaranteed by TransCanada.

In July, 2015, the company issued $750-million of medium-term notes maturing on July 17, 2025, bearing interest at 3.30 per cent.

The net proceeds of these offerings will be used for general corporate purposes and to reduce short-term indebtedness which was used to finance a portion of the company's capital program and for general corporate purposes.

Preferred share rate reset and conversion

In June, 2015, Series 3 shareholders converted 5.5 million of the company's 14 million outstanding Series 3 cumulative redeemable first preferred shares on a one-for-one basis into Series 4 floating-rate cumulative redeemable first preferred shares. The rate on the Series 3 shares was reset and they will now pay an annual fixed dividend rate of 2.152 per cent on a quarterly basis for the five-year period which began on June 30, 2015. The Series 4 shares will pay a floating quarterly dividend for the same five-year period with the rate set for the first quarterly floating rate period (June 30, 2015, to but excluding Sept. 30, 2015) at 1.945 per cent per annum and will be reset every quarter going forward.

Teleconference and webcast

The company will hold a teleconference and webcast on Friday, July 31, 2015, to discuss its second quarter 2015 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. Mountain Time/11 a.m. Eastern Time.

Analysts, members of the media and other interested parties are invited to participate by calling 866-225-6564 or 416-340-2218 (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 the company's website.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight EDT on Aug. 7, 2015. Please call 800-408-3053 or 905-694-9451 (Toronto area) and enter pass code 5657146.

The unaudited interim consolidated financial statements and management's discussion and analysis (MD&A) are available under TransCanada's profile on SEDAR, with the U.S. Securities and Exchange Commission on EDGAR, and on the TransCanada website.

                                                                                       
                              FINANCIAL HIGHLIGHTS
                (In millions of dollars, except per share amounts)

                                          Three months ended       Six months ended  
                                                    June 30,               June 30,      
                                             2015       2014       2015        2014
Income
Revenue                                    $2,631     $2,234     $5,505      $5,118
Net income attributable to common
shares                                        429        416        816         828
Per common share -- basic and
diluted                                     $0.60      $0.59      $1.15       $1.17
Comparable EBITDA                           1,367      1,217      2,898       2,613
Comparable earnings                           397        332        862         754
Per common share                            $0.56      $0.47      $1.22       $1.07
Operating cash flow
Funds generated from operations             1,061        917      2,214       2,019
(Increase)/decrease in operating
working capital                              (92)        202      (485)          79
Net cash provided by operations               969      1,119      1,729       2,098
Investing activities
Capital expenditures                          966        893      1,772       1,637
Capital projects under development            172        193        335         297
Equity investments                            105         40        198         129
Proceeds from sale of assets, net
of transaction costs                            -        187          -         187
Dividends paid
Per common share                            $0.52      $0.48      $1.04       $0.96

We seek Safe Harbor.