CALGARY, ALBERTA — (Marketwired) — 11/05/13 — TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada or the Company) today announced comparable earnings for third quarter 2013 of $447 million or $0.63 per share compared to $349 million or $0.50 per share for the same period in 2012, a 26 per cent increase on a per share basis. Net income attributable to common shares for third quarter 2013 was $481 million or $0.68 per share. Funds generated from operations for third quarter 2013 were $1.046 billion, a 21 per cent increase compared to $866 million for the same period in 2012. TransCanada–s Board of Directors also declared a quarterly dividend of $0.46 per common share for the quarter ending December 31, 2013, equivalent to $1.84 per common share on an annualized basis.
“We generated another strong quarter of earnings and cash flow from our portfolio of critical energy infrastructure assets, despite challenges in U.S. natural gas pipelines and cyclical lows in our gas storage business,” said Russ Girling, TransCanada–s president and chief executive officer. “Comparable earnings for the first nine months of 2013 were $1.66 per share, a 15 per cent increase over the same period last year and reflects the return to an eight unit site at Bruce Power, higher Alberta power prices, an increase in New York capacity prices and a higher Canadian Mainline allowed return on equity. Our strong earnings performance has also led to $2.9 billion of cash flow from existing operations year-to-date, an 18 per cent increase compared to the same period last year.”
We are currently in the midst of an unprecedented capital program that will see a significant expansion of our three core businesses. With Energy East, we now have over $38 billion of commercially secured capital projects, which are backed by long-term contracts or cost of service business models. Our portfolio includes approximately $23 billion of crude oil pipelines, $13 billion of natural gas pipelines, and $2 billion of power generation facilities. Over the remainder of the decade, subject to required approvals, our blue-chip portfolio of contracted projects is expected to generate significant growth in earnings and cash flow.
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Comparable earnings for third quarter 2013 were $447 million or $0.63 per share compared to $349 million or $0.50 per share for the same period in 2012. Higher earnings from the Canadian Mainline, Western Power, Bruce Power and U.S. Power were partially offset by lower contributions from U.S. Natural Gas Pipelines.
Net income attributable to common shares for third quarter 2013 was $481 million or $0.68 per share compared to $369 million or $0.52 per share in third quarter 2012.
Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Oil Pipelines:
Teleconference – Audio and Slide Presentation:
We will hold a teleconference and webcast on Tuesday, November 5, 2013 to discuss our third quarter 2013 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. (MST) / 11 a.m. (EST).
Analysts, members of the media and other interested parties are invited to participate by calling 866.226.1792 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 (EST) on November 12, 2013. Please call 800.408.3053 or 905.694.9451 and enter pass code 6573719.
The unaudited interim Consolidated Financial Statements and Management–s Discussion and Analysis (MD&A) are available 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 4, 2013 and 2012 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, 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 4, 2013.
Quarterly report to shareholders
Third quarter 2013
Financial highlights
Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See non-GAAP measures section for more information.
Management–s discussion and analysis
November 4, 2013
This management–s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and nine months ended September 30, 2013, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2013 which have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our December 31, 2012 audited consolidated financial statements and notes and the MD&A in our 2012 Annual Report, which have been prepared in accordance with U.S. GAAP.
About this document
Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries.
Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2012 Annual Report.
All information is as of November 4, 2013 and all amounts are in Canadian dollars, unless noted otherwise.
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management–s assessment of our future plans and financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this MD&A may include information about the following, among other things:
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:
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 2012 Annual Report.
You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.
FOR MORE INFORMATION
You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR ().
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 are unlikely to be comparable to similar measures presented by other entities.
EBITDA and EBIT
We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is an effective measure of our performance and an effective tool for evaluating trends in each segment. It is calculated in the same way as EBITDA, less depreciation and amortization.
Funds generated from operations
Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is an effective measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period. See Financial condition section for a reconciliation to net cash provided by operations.
Comparable measures
We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Our decision not to include a specific item is subjective and made after careful consideration. These may include:
In our calculation of comparable earnings, we exclude 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.
Reconciliation of non-GAAP measures
Results – Third quarter 2013
Net income attributable to common shares was $481 million this quarter compared to $369 million in third quarter 2012.
Net income attributable to common shares was $1,292 million for the nine months ended September 30, 2013 compared to $993 million for the same period in 2012 . The 2013 results included $84 million of net income related to 2012 from the NEB decision on the Canadian Restructuring Proposal. Also included in net income was a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax. These amounts were excluded from comparable earnings. The 2012 results included an after-tax charge of $15 million ($20 million pre-tax) relating to the Sundance A PPA arbitration decision that was excluded from 2012 comparable earnings as it related to 2011.
Comparable earnings this quarter were $447 million and $0.63 per share, or $98 million and $0.13 per share higher than third quarter 2012.
Comparable earnings for the nine months ended September 30, 2013 were $1,174 million and $1.66 per share, or $162 million and $0.22 per share higher than the same period in 2012.
This was primarily the result of:
Outlook
While the NEB–s March 27, 2013 decision on the Canadian Restructuring Proposal for tolls and services on the Canadian Mainline may result in increased variability and seasonality of cash flow, we expect it to have a positive impact on the earnings outlook for 2013 previously included in our 2012 Annual Report. The NEB approved an allowed ROE of 11.50 per cent on 40 per cent deemed common equity, fixed multi-year firm tolls through 2017 and a new incentive mechanism. In addition, we expect the increase in 2013 power prices in Western Power to also have a positive impact on our previously disclosed earnings outlook for 2013. See the MD&A in our 2012 Annual Report for further information about our outlook.
Natural Gas Pipelines
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
CANADIAN PIPELINES
Comparable EBITDA and net income for our rate-regulated Canadian Pipelines are affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and taxes also impact comparable EBITDA and EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.
Canadian Mainline–s comparable earnings increased by $20 million for the three months ended September 30, 2013 and $61 million for the nine months ended September 30, 2013 compared to the same periods in 2012 because of the impact of the NEB–s March 2013 decision (the NEB decision) on the Canadian Restructuring Proposal. Among other items, the NEB approved an ROE of 11.50 per cent on a 40 per cent deemed common equity for the years 2012 through to 2017 compared to the last approved ROE of 8.08 per cent on a deemed common equity of 40 per cent that was used to record earnings in 2012. Net income of $285 million for the nine months ended September 30, 2013 included $84 million related to the 2012 impact of the NEB decision.
Net income for the NGTL System (formerly known as the Alberta System) increased by $4 million for the three months ended September 30, 2013 and $18 million for the nine months ended September 30, 2013 compared to the same periods in 2012 because of a higher average investment base and termination of the annual fixed OM&A costs component included in the 2010 – 2012 Revenue Requirement Settlement which expired at the end of 2012. Results for 2013 reflect the last approved ROE of 9.70 per cent on deemed common equity of 40 per cent and no incentive earnings.
U.S. PIPELINES AND INTERNATIONAL
EBITDA for our U.S. operations is generally affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.
Comparable EBITDA for the U.S. and international pipelines was US$166 million for the three months ended September 30, 2013 and US$576 million for the nine months ended September 30, 2013 compared to US$192 million and US$665 million for the same periods in 2012. This was the net effect of:
COMPARABLE DEPRECIATION AND AMORTIZATION
Comparable depreciation and amortization was $248 million for the three months ended September 30, 2013 and $733 million for the nine months ended September 30, 2013 compared to $231 million and $697 million for the same periods in 2012 mainly because of a higher investment base on the NGTL System and the impact of the NEB decision on the Canadian Mainline.
Oil Pipelines
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
Comparable EBITDA from our Keystone Pipeline System is generated primarily by providing pipeline capacity to shippers on a take-or-pay basis in exchange 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 $13 million for the three months ended September 30, 2013 and $34 million for the nine months ended September 30, 2013 compared to the same periods in 2012. These increases reflected higher revenues primarily resulting from:
BUSINESS DEVELOPMENT
Business development expenses in the first nine months of 2013 were $6 million higher than the same period in 2012 because of increased activity on various oil pipeline development projects.
Energy
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
Comparable EBITDA for Energy increased by $143 million for the three months ended September 30, 2013 compared to the same period in 2012. The increase was the effect of:
Comparable EBITDA for Energy increased by $336 million for the nine months ended September 30, 2013 compared to the same period in 2012. The increase reflected:
CANADIAN POWER
Western and Eastern Power(1)
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
Western Power–s comparable EBITDA increased by $25 million for the three months ended September 30, 2013 compared to the same period in 2012. The increase was mainly due to lower PPA costs, increased utilization of the Sundance B PPA and the return to service of the Sundance A PPA Unit 1 in early September 2013.
Western Power–s comparable EBITDA increased by $69 million for the nine months ended September 30, 2013 compared to the same period 2012. The increase was mainly due to higher realized power prices, increased utilization of the Sundance B PPA and lower PPA costs.
In first quarter 2012, we recorded revenues and costs related to the Sundance A PPA as though the outages of Units 1 and 2 were interruptions of supply in accordance with the terms of the PPA. In July 2012, we received the Sundance A PPA arbitration decision which determined the units were in force majeure in first quarter 2012. In response, we recorded a charge of $30 million in second quarter 2012 equivalent to the pre-tax income we had recorded in first quarter 2012. Sundance A Unit 1 returned to service in early September 2013 and third quarter revenues and costs included these volumes.
Average spot market power prices in Alberta increased by eight per cent to $84 per MWh for the three months ended September 30, 2013 and 53 per cent to $90 per MWh for the nine months ended September 30, 2013, compared to the same periods in 2012. These increases were mainly the result of plant outages and increased power demand.
Western Power–s revenue decreased by $14 million for the three months ended September 30, 2013 compared to the same period in 2012 because of lower purchased volumes under the Sheerness PPA primarily due to higher planned outage days, partially offset by the return to service of Sundance A Unit 1 in early September 2013 and higher generation volumes.
Western Power–s revenue decreased by $41 million for the nine months ended September 30, 2013 compared to the same period in 2012 because of the Sundance A PPA revenue recorded in first quarter 2012 partially offset by the return to service of Sundance A Unit 1 in early September 2013 and higher generation volumes.
Western Power–s commodity purchases resold decreased by $32 million for the three months ended September 30, 2013 compared to the same period in 2012 because of lower purchased volumes and costs under the Sheerness PPA partially offset by the return to service of Sundance A Unit 1 in September 2013. Western Power–s commodity purchases resold decreased by $22 million for the nine months ended September 30, 2013 compared to the same period in 2012 due to the Sundance A PPA costs recorded in first quarter 2012 and lower PPA costs partially offset by the return to service of Sundance A Unit 1 in early September 2013.
Eastern Power–s comparable EBITDA and revenue decreased by $7 million and $12 million, respectively, for the three months ended September 30, 2013 compared to the same period in 2012. Eastern Power–s comparable EBITDA and revenue decreased by $3 million and $13 million for the nine months ended September 30, 2013 compared to the same period in 2012, respectively. The decreases were mainly due to:
Income from equity investments increased by $10 million for the three months ended September 30, 2013 compared to the same period in 2012 due to higher earnings under the Sundance B PPA, because of higher utilization. Income from equity investments increased by $81 million for the nine months ended September 30, 2013 compared to the same period in 2012 because of higher earnings under the Sundance B PPA which reflected higher realized power prices and higher utilization, as well as higher earnings from Portlands Energy which were the result of an unplanned outage in second quarter 2012.
Approximately 70 per cent of Western Power sales volumes were sold under contract this quarter compared to 91 per cent in third quarter 2012. To reduce exposure to spot market prices in Alberta, Western Power enters into fixed price forward sales to secure future revenue and a portion of our power is retained to be sold in the spot market or under shorter-term forward arrangements. The amount sold forward will vary depending on market conditions and market liquidity and has historically ranged between 25 to 75 per cent of expected future production with a higher proportion being hedged in the near term periods. Such forward sales may be completed with medium and large industrial and commercial companies and other market participants and will affect our average realized price (versus spot price) in future periods.
BRUCE POWER
Our proportionate share
Equity income from Bruce A increased by $84 million for the three months ended September 30, 2013 compared to the same period in 2012. The increase was mainly due to:
Equity income from Bruce A increased by $227 million for the nine months ended September 30, 2013 compared to the same period in 2012. The increase was mainly due to:
The increase for the nine months ended September 30, 2013 was partially offset by the impact of the Unit 4 life extension planned outage which began in August 2012 and was completed in April 2013.
Equity income from Bruce B increased by $17 million for the three months ended September 30, 2013 compared to the same period in 2012. The increase was primarily due to lower lease expense recognized in third quarter 2013 based on the terms of the lease agreement with Ontario Power Generation. A similar lease expense adjustment was recognized in second quarter 2012.
Equity income from Bruce B decreased by $54 million for the nine months ended September 30, 2013 compared to the same period in 2012. The decrease was mainly due to lower volumes and higher operating costs resulting from higher planned outage days.
Under the contract with the OPA, all of the output from Bruce A 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 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 monthly average spot price exceeds the floor price. We currently expect 2013 spot prices to be less than the floor price for the year and therefore no amounts received under the floor price mechanism in 2013 are expected to be repaid.
Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.
The overall plant availability percentage in 2013 is expected to be in the mid 80s for Bruce A and the high 80s for Bruce B. No further planned maintenance is scheduled for the remainder of 2013.
U.S. POWER
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
U.S. Power–s comparable EBITDA was US$111 million for the three months ended September 30, 2013 compared to US$87 million for the same period in 2012. The increase was the net effect of:
U.S. Power–s comparable EBITDA was US$258 million for the nine months ended September 30, 2013 compared to US$161 million for the same period in 2012. The increase was the net effect of:
Commodity prices were higher for the three and nine months ended September 30, 2013 compared to the same periods in 2012. In 2013, natural gas prices recovered from low levels in 2012 back to the five year average while gas production levels remained flat. The higher gas prices along with hot weather in July resulted in higher spot power prices in the predominantly gas-fired New England and New York power markets for the nine months ended September 30, 2013.
Physical sales volumes for the three and nine months ended September 30, 2013 were lower than the same periods in 2012 due to lower purchased volumes sold to wholesale, commercial and industrial customers in New England partially offset by increased volumes in our PJM markets. Generation volumes were lower, mainly due to lower generation at our Ravenswood natural gas fueled facility in New York partially offset by higher output at our hydro facilities.
Power revenue of US$401 million for the three months ended September 30, 2013 has decreased compared to US$408 million for the same period in 2012 mainly due to lower sales to wholesale, commercial and industrial customers in New England, offset by higher realized power prices. Power revenue of US$1,151 million for the nine months ended September 30, 2013 increased compared to US$836 million for the same period in 2012 mainly due to higher realized power prices, partially offset by lower volumes.
Capacity revenue was US$93 million for the three months ended September 30, 2013 and US$217 million for the nine months ended September 30, 2013 compared to US$75 million and US$181 million for the same periods in 2012. New York Zone J spot capacity prices were approximately 25 per cent higher than last year on a year to date basis. This increase in spot capacity prices and the impact of hedging activities resulted in higher realized prices in New York, partially offset by lower capacity prices in New England.
Commodity purchases resold were US$249 million for the three months ended September 30, 2013 compared to US$268 million for the same period in 2012. The decrease was due to lower volumes of purchases as sales to wholesale, commercial and industrial customers in New England offset by higher prices to purchase the power to fulfill sales commitments. Commodity purchases resold were US$752 million for the nine months ended September 30, 2013 compared to US$548 million for the same period in 2012 as the increase in prices to fulfill power sales commitments to wholesale, commercial and industrial customers more than offset the lower purchased volumes.
Plant operating costs and other, which includes fuel gas consumed in generation, increased by US$73 million for the nine months ended September 30, 2013 compared to the same period in 2012 because of higher natural gas fuel prices.
As at September 30, 2013, approximately 1,400 GWh or 36 per cent of U.S. Power–s planned generation is contracted for the remainder of 2013, and 2,900 GWh or 30 per cent for 2014. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.
NATURAL GAS STORAGE
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
Comparable EBITDA decreased by $8 million for the three months ended September 30, 2013 and $11 million for the nine months ended September 30, 2013 compared to the same periods in 2012 because of lower realized natural gas storage spreads partially offset by incremental earnings from CrossAlta resulting from the acquisition of the remaining 40 per cent interest in December 2012.
Recent developments
NATURAL GAS PIPELINES
Canadian Mainline
On March 27, 2013, the NEB issued its decision on our application to change the business structure and the terms and conditions of service for the Canadian Mainline. Since implementation of the decision on July 1, 2013, an additional 1.3 Bcf/d of firm service originating at Empress has been contracted for, more than doubling the contracted capacity at this location.
Certain additional changes to the Canadian Mainline–s tariff were considered as a separate application which was heard in an oral hearing that concluded on September 23, 2013. The changes requested included provisions to diversions and alternate receipt points as well as modifying renewal notification for firm Mainline service. The NEB denied the material changes in its decision issued on October 10, 2013, with reasons to follow.
In September 2013, we reached a settlement with local natural gas distribution companies in Ontario and Quebec on long-term tolls that will allow us to provide customers with the flexibility to source gas from various geographic locations within the eastern triangle segment of the system while ensuring that the tolls for the Canadian Mainline are set at levels that recover the costs of providing that flexibility. We expect to file an application for approval of the settlement with the NEB by the end of 2013 that includes a proposed January 1, 2015 implementation date.
NGTL System expansion projects
We continued to expand the NGTL System and have placed approximately $700 million of new facilities in service to date in 2013. We also received NEB approval to construct and operate an additional approximately $300 million of new facilities.
In August 2013, we signed agreements with Progress Energy Canada Ltd. (Progress) for approximately two Bcf/d of firm gas transportation services to underpin the development of a major pipeline extension of the NGTL System. The proposed North Montney Project will also include an interconnection with our proposed Prince Rupert Gas Transmission (PRGT) project to provide natural gas supply to the proposed Pacific NorthWest LNG export facility near Prince Rupert, B.C. and is expected to cost approximately $1.7 billion, which includes $100 million for downstream facilities. Under the commercial arrangements with Progress, receipt volumes are expected to increase between 2016 and 2019 to an aggregate volume of approximately two Bcf/d and delivery volumes to the PRGT project are expected to be approximately 2.1 Bcf/d beginning in 2019. We are also in discussions with other parties that have expressed interest in obtaining transportation services that would utilize the North Montney facilities. We plan to file an application for approval to construct and operate the North Montney Project in fourth quarter 2013.
Also in fourth quarter 2013, we expect to begin a notification process to potential shippers for a proposal to provide export delivery service to Vanderhoof, B.C. through the use of capacity arrangements on the Coastal GasLink pipeline.
A settlement of the NGTL System annual revenue requirement for the years 2013 and 2014 was reached with shippers and other interested parties in August 2013. The settlement fixes return at 10.1 per cent on a 40 per cent deemed common equity, establishes an increase in the composite depreciation rate to 3.05 per cent and 3.12 per cent for 2013 and 2014, respectively, and fixes the OM&A for 2013 at $190 million and 2014 at $198 million with any variance to our account. In August 2013, we requested and received approval for changes to existing interim rates to reflect the settlement, effective September 1, 2013, pending a decision on the settlement application. On November 1, 2013, the NEB approved the settlement and 2013 final tolls, as filed. Third quarter 2013 results do not reflect the impact of this decision.
Coastal GasLink Pipeline Project
We are currently focused on community, landowner, government and First Nations engagement as the Coastal GasLink pipeline project advances through the regulatory process with the B.C. Environmental Assessment Office and the Canadian Environmental Assessment Agency. We will solicit shipper interest in the provision of delivery service near Vanderhoof, B.C. in fourth quarter 2013.
ANR Lebanon Lateral Reversal Project
Following a successful binding open season which concluded in October 2013, we have executed firm transportation contracts for 350 MMcf/d at maximum tariff rates for 10 years on the ANR Lebanon Lateral Reversal project. The project will require modification to existing facilities at relatively minor capital expenditures, which are expected to be completed in first quarter 2014. Contracted volumes will increase throughout 2014 generating incremental earnings. The project will substantially increase our ability to receive gas on ANR–s southeast mainline from the Utica/Marcellus shale plays.
Great Lakes
On September 27, 2013, we filed with FERC a settlement with our customers to modify the transportation rates beginning on November 1, 2013. The settlement is expected to be approved by FERC before the end of the year. The settlement establishes maximum recourse transportation rates on the Great Lakes system. Commencing November 2013, rates will increase, compared to current rates, by approximately 21 percent. This will result in a modest increase in the portion of revenue derived from the recourse rate contracts. The settlement includes a moratorium on filing rate cases or challenging the settlement rates between November 1, 2013 and March 31, 2015 and requires that we file to have new rates in effect no later than January 1, 2018.
Sale of U.S. Pipeline assets to TC PipeLines, LP
In July 2013, we closed the sale of a 45 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) to TC PipeLines, LP for an aggregate purchase price of US$1.05 billion, which included US$146 million representing 45 per cent of GTN–s debt, plus normal closing adjustments.
We continue to hold a 30 per cent ownership interest in both pipelines. We also hold a 28.9 per cent interest in TC PipeLines, LP for which we are the General Partner.
Mexican Pipelines
The construction of the Tamazunchale Pipeline Extension project and related compression facilities is proceeding. Although the end of first quarter 2014 continues to be the target in-service date, the construction schedule has been challenged with various issues including the discovery of several archeological finds. The project team continues to monitor and evaluate impacts of related schedule delays. The Topolobampo and Mazatlan projects in northwest Mexico are advancing as planned with engineering and permitting activities.
OIL PIPELINES
Gulf Coast Project
We are constructing a US$2.3 billion 36-inch pipeline from Cushing, Oklahoma to the U.S. Gulf Coast and expect to begin delivering crude oil to Port Arthur, Texas near the end of 2013. Construction is approximately 95 per cent complete.
We have commenced construction of the US$300 million 76 km (47 mile) Houston Lateral pipeline to transport crude oil to Houston, Texas refineries, which is expected to be complete in 2014.
The Gulf Coast Project will have a capacity of up to 700,000 Bbl/d.
Keystone XL Pipeline
On March 1, 2013, the U.S. DOS released its Draft Supplemental Environmental Impact Statement for the Keystone XL Pipeline. The impact statement reaffirmed that construction of the proposed pipeline from the U.S./Canada border in Montana to Steele City, Nebraska would not result in any significant impact to the environment. The DOS continues to review comments on the impact statement that it received during a public comment period that ended on April 22, 2013. Once the DOS has completed its review, it is anticipated it will issue a Final Supplemental Environmental Impact Statement and then consult with other governmental agencies and provide an additional opportunity for public comment during a National Interest Determination period of up to 90 days, before making a decision on our Presidential Permit application.
We anticipate the pipeline to be in service approximately two years following the receipt of the Presidential Permit. The US$5.3 billion cost estimate will increase depending on the timing of the permit. As of September 30, 2013, we have invested US$2.0 billion in the project.
Energy East Pipeline
On August 1, 2013, we announced we are moving forward with the 1.1 million Bbl/d Energy East Pipeline project as it received approximately 900,000 Bbl/d of firm, long-term contracts in its open season to transport crude oil from Western Canada to Eastern refineries and export terminals. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets and, subject to regulatory approvals, is anticipated to be in service by late 2017 for deliveries in Quebec and 2018 for deliveries in New Brunswick. We intend to file the necessary regulatory applications for approvals to construct and operate the pipeline project and terminal facilities in the first half of 2014.
Northern Courier Pipeline
In April 2013, we filed a permit application with the Alberta regulator after completing the required Aboriginal and stakeholder engagement and associated field work.
On October 30, 2013, Suncor Energy announced that the Fort Hills Energy Limited Partnership is proceeding with the Fort Hills oil sands mining project and expects to begin producing crude oil as early as late 2017. Our Northern Courier Pipeline project is expected to be completed in 2017 and will transport crude oil from the Fort Hills mine site to Suncor–s tank facilities located north of Fort McMurray.
Heartland Pipeline and TC Terminals
In May 2013, we announced we had reached binding long-term shipping agreements to build, own and operate the proposed Heartland Pipeline and TC Terminals projects.
The proposed projects will include a 200 km (125 mile) crude oil pipeline connecting the Edmonton region to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton. We anticipate the pipeline could transport up to 900,000 Bbl/d, while the terminal is expected to have storage capacity for up to 1.9 million barrels of crude oil. These projects together have a combined cost estimated at $900 million and are expected to come into service during the second half of 2015.
We filed a permit application for the terminal facility with the Alberta regulator in May 2013 and filed an application for the pipeline on October 25, 2013.
Grand Rapids Pipeline
In May 2013, we filed a permit application with the Alberta regulator after completing the required Aboriginal and stakeholder engagement and associated field work.
ENERGY
Ontario Solar
In late 2011, we agreed to buy nine Ontario solar projects (combined capacity of 86 MW) from Canadian Solar Solutions Inc. for approximately $470 million. On June 28, 2013 we completed the acquisition of the first project for $55 million and on September 30, 2013 we completed the acquisition of two additional projects for $99 million. We expect the acquisition of the remaining projects to close between late 2013 and 2014, all subject to satisfactory completion of the related construction activities and regulatory approvals. All power produced will be sold under 20-year PPAs with the OPA.
Sundance A
Sundance A Unit 1 returned to service in early September 2013. Sundance B Unit 2 returned to service in October 2013. TransAlta shut down both units in December 2010 and was ordered by an arbitration panel in July 2012 to rebuild these units.
Bruce Power
On April 5, 2013, Bruce Power announced that it had reached an agreement with the OPA to extend the Bruce B floor price through to the end of the decade which is expected to coincide with the 2019 and 2020 end of life dates for the Bruce B units.
Bruce Power returned Unit 4 to service on April 13, 2013 after completing an expanded life extension outage investment program which began in August 2012. It is anticipated that this investment will allow Unit 4 to operate until at least 2021.
Bruce Power–s fully operational eight unit site is now capable of producing more than 6,200 MW towards Ontario–s power supply.
Becancour
In June 2013, Hydro-Quebec notified us that it would exercise its option to extend the agreement to suspend all electricity generation from the Becancour power plant through 2014 and the suspension was approved in August 2013. Under the suspension agreement, Hydro-Quebec has the option (subject to certain conditions) to extend the suspension every year until regional electricity demand levels recover. We continue to receive capacity payments while generation is suspended.
Other income statement items
Comparable interest expense was $235 million for the three months ended September 30, 2013 compared to $249 million for the same period in 2012 because of the following:
Comparable interest expense was $744 million for the nine months ended September 30, 2013 compared to $730 million for the same period in 2012 because of the following:
Comparable interest income and other was $32 million for the nine months ended September 30, 2013, compared to $66 million for the same period in 2012 because we had realized losses in 2013 compared to realized gains in 2012 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.
Comparable income taxes expense were $172 million and $464 million for the three and nine months ended September 30, 2013, respectively, compared to $123 million and $354 million for the same periods in 2012. The increase was mainly the result of higher pre-tax earnings in 2013 compared to 2012 combined with changes in the proportion of income earned between Canadian and foreign jurisdictions.
Financial condition
We strive to maintain financial strength and flexibility in all parts of an economic cycle, and rely on our operating cash flows to sustain our business, pay dividends and fund a portion of our growth.
We access capital markets to meet our financing needs, manage our capital structure and preserve our credit ratings.
We believe we have the capacity to fund our existing capital program through predictable cash flow from our operations, access to the capital markets, cash on hand and substantial committed credit facilities.
CASH FROM OPERATING ACTIVITIES
Net cash provided by operations was $1,118 million for the three months ended September 30, 2013 and $2,665 million for the nine months ended September 30, 2013 compared to $1,101 million and $2,546 million for the same periods in 2012, respectively, mainly due to an increase in earnings.
At September 30, 2013, our current assets were $2.4 billion and current liabilities were $4.8 billion, leaving us with a working capital deficit of $2.4 billion compared to $3.1 billion at the end of 2012. This working capital deficiency is considered to be in the normal course of business and is managed through our ability to generate cash flow and our ongoing access to the capital markets.
CASH USED IN INVESTING ACTIVITIES
Our capital expenditures this quarter were primarily related to the Gulf Coast Project, expansion of the NGTL System and construction of the Mexican pipelines.
Our cash used in equity investments decreased this quarter and year to date due to lower capital spending at Bruce Power.
On June 28, 2013, we completed the acquisition of the first Ontario Solar project for $55 million. On September 30, 2013, we completed the acquisition of two additional Ontario Solar projects for $99 million.
CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES
In January 2013, we issued US$750 million of senior notes, maturing on January 15, 2016 and bearing interest at 0.75 per cent per annum.
In March 2013, we completed a public offering of 24 million Series 7 cumulative redeemable first preferred shares at a price of $25 per share for aggregate gross proceeds of $600 million. Investors will be entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly. Investors will have the right to convert their shares into cumulative redeemable first preferred shares, Series 8, every fifth year beginning on April 30, 2019. The holders of Series 8 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 plus 2.38 per cent.
In June 2013, we retired US$350 million of 4.00 per cent senior notes.
In July 2013, we issued US$500 million of three-year London Interbank Offered Rate-based floating rate notes maturing on June 30, 2016, bearing interest at an initial annual rate of 0.95 per cent.
Also in July 2013, we issued $450 million of ten-year and $300 million of 30-year medium term notes maturing on July 19, 2023 and November 15, 2041, bearing interest at rates of 3.69 and 4.55 per cent per annum, respectively.
In August 2013, we retired US$500 million of 5.05 per cent senior notes.
In October 2013, we issued US$625 million of senior notes, maturing on October 16, 2023 and bearing interest at 3.75 per cent per annum and US$625 million of senior notes, maturing on October 16, 2043 and bearing interest at 5.0 per cent per annum.
The net proceeds of these offerings are intended to be used for general corporate purposes and to reduce short-term indebtedness, which was used to fund a portion of our capital program.
Also in October 2013, we redeemed four million outstanding 5.60 per cent Cumulative Redeemable First Preferred Shares Series U. The Series U Shares were redeemed at a price of $50 per share plus $0.5907 of accrued and unpaid dividends. The total face value of the outstanding Series U Shares was $200 million and carried an aggregate of $11.2 million in annualized dividends.
In May 2013, TC PipeLines, LP completed a public offering of 8,855,000 common units at US$43.85 per common unit for gross proceeds of US$388 million. We contributed an additional approximate US$8 million to maintain our general partnership interest and did not purchase any other units. Upon completion of this offering, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent.
In July 2013, TC PipeLines, LP entered into a five-year, US$500 million term loan, maturing July 2018. The proceeds from the public offering, term loan and partner contribution were used to finance the acquisition of the 45 per cent interest in GTN and Bison from us.
DIVIDENDS
On November 4, 2013 we declared quarterly dividends as follows:
CREDIT FACILITIES
We use committed, revolving credit facilities to support our commercial paper programs along with additional demand facilities for general corporate purposes including issuing letters of credit and providing additional liquidity.
At September 30, 2013, we had $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 $436 million primarily due to the completion or advancement of capital projects. Our other purchase commitments decreased by $292 million. There were no other material changes to our contractual obligations in third quarter 2013 or to payments due in the next five years or after. See the MD&A in our 2012 Annual Report for more information about our contractual obligations.
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.
Please see our 2012 Annual Report for more information about the risks we face in our business. In addition to those disclosed risks, in the NEB–s March 2013 decision on our Canadian Restructuring Proposal, the NEB found that the fundamental business risk facing the Canadian Mainline has increased. The tolling framework created by the NEB decision results in higher variability in cash flows and greater uncertainty about the ultimate recovery of the Canadian Mainline–s cost of service. Otherwise, our risks have not changed substantially since December 31, 2012.
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, 2013, we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration of $228 million with one counterparty at September 30, 2013 (December 31, 2012 – $259 million). This amount is secured by a guarantee from the counterparty–s parent company and we anticipate collecting the full amount.
We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.
FOREIGN EXCHANGE RISK
Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. operations continue to grow, our exposure to changes in currency rates increases. Some of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.
We use foreign exchange derivatives to manage other foreign exchange exposures, including those that arise on some of our regulated assets. We defer some of the realized gains and losses on these derivatives as regulatory assets and liabilities until we recover from or pay them to shippers according to the terms of the shipping agreements.
AVERAGE EXCHANGE RATE – U.S. TO CANADIAN DOLLARS
The impact of changes in the value of the U.S. dollar on our U.S. operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below. Comparable EBIT is a non-GAAP measure.
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:
BALANCE SHEET PRESENTATION OF DERIVATIVE INSTRUMENTS
The fair value of the derivative instruments on the balance sheet.
DERIVATIVES IN CASH FLOW HEDGING RELATIONSHIPS
The components of other comprehensive income (OCI) related to derivatives in cash flow hedging relationships.
CREDIT RISK RELATED CONTINGENT FEATURES
Derivatives contracts often contain financial assurance provisions that may require us to provide collateral if a credit risk-related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade).
Based on contracts in place and market prices at September 30, 2013, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $18 million (December 31, 2012 – $37 million), with collateral provided in the normal course of business of nil (December 31, 2012 – nil). If the credit-risk-related contingent features in these agreements had been triggered on September 30, 2013, we would have been required to provide collateral of $18 million (December 31, 2012 – $37 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.
We feel we have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
FAIR VALUE HIERARCHY
Assets and liabilities that are recorded at fair value are required to be categorized into three levels based on the fair value hierarchy.
A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $3 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III at September 30, 2013.
Other information
CONTROLS AND PROCEDURES
Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at September 30, 2013, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
There were no changes in third quarter 2013 that had or are likely to have a material impact on our internal control over financial reporting.
Management continues to implement an Enterprise Resource Planning (ERP) system that will likely affect some processes supporting internal control over financial reporting. The implementation is expected to begin January 1, 2014.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, AND ACCOUNTING CHANGES
When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgment. We also regularly assess the assets and liabilities themselves.
Our significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2012 other than described below. You can find a summary of our significant accounting policies and critical accounting estimates in our 2012 Annual Report.
Changes in accounting policies for 2013
Balance sheet offsetting/netting
Effective January 1, 2013, we adopted the ASU on disclosures about balance sheet offsetting as issued by the FASB to enable understanding of the effects of netting arrangements on our financial position. Adoption of the ASU has resulted in increased qualitative and quantitative disclosures about certain derivative instruments that are either offset in accordance with current U.S. GAAP or are subject to a master netting arrangement or similar agreement.
Accumulated other comprehensive income
Effective January 1, 2013, we adopted the ASU on reporting of amounts reclassified out of AOCI as issued by the FASB. Adoption of the ASU has resulted in providing additional qualitative and quantitative disclosures about significant amounts reclassified out of AOCI into net income.
Future accounting changes
Obligations resulting from joint and several liability arrangements
In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This ASU is effective retrospectively for fiscal years, and interim reporting periods within those years, beginning after December 15, 2013. We are evaluating the impact that adopting the ASU would have on our consolidated financial statements, but do not expect it to have a material impact.
Foreign currency matters – cumulative translation adjustment
In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This ASU is effective prospectively for fiscal years, and interim reporting periods within those years, beginning after December 15, 2013. Early adoption is allowed as of the beginning of the entity–s fiscal year. We are evaluating the impact that adopting this ASU would have on our consolidated financial statements, but do not expect it to have a material impact.
Unrecognized tax benefit
In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This ASU is effective prospectively for fiscal years and interim reporting periods within those years, beginning after December 15, 2014. Early adoption is permitted. We are evaluating the impact that adopting the ASU would have on our consolidated financial statements, but do not expect it to have a material impact.
QUARTERLY RESULTS
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT
Quarter-over-quarter revenues and net income sometimes fluctuate. The causes of these fluctuations vary across our business segments.
In Natural Gas Pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:
In Oil Pipelines, annual revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable.
In Energy, quarter-over-quarter revenues and net income are affected by:
FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER
1. Basis of Presentation
These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TransCanada–s annual audited consolidated financial statements for the year ended December 31, 2012. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada–s 2012 Annual Report.
These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2012 audited consolidated financial statements included in TransCanada–s 2012 Annual Report. Certain comparative figures have been reclassified to conform with the current period–s presentation.
Earnings for interim periods may not be indicative of results for the fiscal year in the Company–s Natural Gas Pipelines segment due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company–s Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company–s investments in electrical power generation plants and non-regulated gas storage facilities.
USE OF ESTIMATES AND JUDGEMENTS
In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these condensed consolidat