TC Energy Corp (TRP) 2003 Q3 法說會逐字稿

All participants, please stand by your conference is ready to begin. Good afternoon, ladies and gentlemen. Welcome to the TransCanada third quarter results conference call. I would now like to turn the meeting over to Mr. David Bennetta, Director of Investor Relations. Please go ahead, Mr. Bennetta.

Thanks very much, good afternoon, everyone. I would like to take this opportunity to welcome you this afternoon, including those of you who are joining us through the Internet. We're pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2003 third quarter financial results and other general issues concerning TransCanada. With me today are Hal Kvisle, President and Chief Executive Officer, Russ Girling, Executive Vice President and Chief Financial Officer, and Lee Hobbs, Vice President and Controller.

Hal and Russ will begin this afternoon with some comments on our results and other general issues pertaining to TransCanada, and following their opening remarks we'll turn the call over to the conference coordinator for questions. During the question-and-answer period, we'll accept questions from the investment community first, followed by questions from the media. Before Hal begins I would like to remind that you certain information in this presentation is forward- looking and is subject to important risks and uncertainties. The results or events predicted in this information may differ from actual results or events. Factors which could cause actual results to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement strategic initiatives and whether such strategic initiatives will yield the expected benefits. The availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and power industries and the prevailing economic conditions in North America. For additional information on these and other factors see the reports filed by TransCanada with Canadian Security Regulators and with the United States Securities and Exchange Commission. TransCanada disclaims any intention or obligation to update or revise any forward-looking statements whether as a result of new information, future events or otherwise. With that, I will now turn the call over to Hal Kvisle.

Thank you, David. Good afternoon, everyone and thank you for joining us. The challenge of meeting the growing demands for energy draws increasing attention, TransCanada took steps in the third quarter to continue to strengthen its position as a key North American energy infrastructure company.

Initiatives like our increased ownership in Portlands Natural Gas and Foothills Pipeline, both of which I will describe in detail in a moment, along with the development of northern gas reserves, the importation of liquified natural gas and numerous initiatives in the power sector are strategically important to bolstering TransCanada's role within North American energy markets. Our gas and power initiatives, some immediate, some longer term, highlight our emphasis on positioning TransCanada for long-term growth and value creation, while maintaining strong operational and financial performance. I'm pleased today to report interim results that highlight the continued strength of our Cash Flow and Balance Sheet and show solid growth in earnings. It's our continued financial strength along with our expert people, premium pipe and power outfits and focused strategies that together place TransCanada in a strong position to capture future opportunities. As detailed in our report to shareholders, TransCanada Corporation's Net Income in the third quarter of 2003 was $248 million or $.51 cents per share. Compared to Net Income of $175 million, or $.37 cents per share over the third quarter of 2002. These results include income recognition and discontinued operations of $50 million or $.10 cents per share of a $100 million dollar after-tax gain that we had initially deferred from the disposition in 2001 of TransCanada's gas marketing business. In addition, TransCanada's Board of Directors today declared a quarterly dividend of $.27 cents per share, for the quarter ended December 31st, 2003 on the outstanding common shares.

This will be the 160th consecutive quarterly Dividend paid by TransCanada and its subsidiary on its common shares. I would like to now take a few moments to review developments in the third quarter and then I will turn the call to Russ Girling who will provide additional detail on our financial results. In our Natural Gas Transmission business, we completed our purchase of the remaining interests of Foothills Pipelines Limited in August. TransCanada now owns 100 percent of Foothills an its subsidiaries. As we discussed in our second quarter conference call, this acquisition strengthens our position to bring Northern Gas, a critical service of new supply to market. Through Foothills and other subsidiaries TransCanada holds the certificates to build the Alaska and Canadian portions of the Alaska Highway Pipeline project. Our primary focus is on the Canadian portion of the project, where TransCanada is uniquely positioned to take a strong and value [inaudible] leadership role. During the quarter we also increased our ownership interest in another of our affiliated pipelines, Portland Natural Gas Transmission System, through two separate transactions. The first transaction, which closed on September 29th, increased our ownership share by more than 10 percent, to 43.42 percent. The second transaction, which we anticipate completing by the end of this year, will increase our ownership of Portland to as much as 73.06 percent, pending the exercise of Gas Metropolitan's right of first refusal. If Gas Metro exercises their right, as they did in the first transaction, we would end up with 61.71 percent, of Portland Natural Gas Transmission System. Portland operates a 471 kilometer interstate natural gas pipeline which connects with TransQuebec and [inaudible] Pipeline, 50 percent owned at TransCanada near Pittsburgh, New Hampshire. Increasing our interest in the Portland system bolsters TransCanada's role as an energy supplier in the U.S. Northeast. Alternative supplies including liquified natural gas imports will be needed by the U.S. Northeast market.

TransCanada expects to play a role in fulfilling that need. To that end, we took an initial step in September with the announcement of the Fair wins LNG project, an equal partnership with Conoco Phillips to develop a regasification facility that could be connected to the Portland pipeline system. TransCanada continues to evaluate other LNG opportunities as well. We're proceeding cautiously but deliberately. We have the financial means. We know the North American natural gas market and we have the pipeline assets, experience, and capacity necessary to move LNG once regasified to market. Let me now discuss recent developments in TransCanada's strong and growing Power business. We announced last Friday an agreement with an affiliate of Irving Oil Limited to build a 90 megawatt natural gas fired co-generation plant. The facility which will be developed and owned by TransCanada will be located on the site of Irving Oil refinery in St. Johns, New Brunswick. The Capital cost of the project will be approximately $85 million dollars. Irving will provide fuel for the plant, and contract for 100 percent of the plant's heat and electricity output under a 20-year term arrangement. Pending regulatory approvals, construction of the plant will begin in November 2003, with an expected in-service date at the end of 2004. Turning now to Bruce. Bruce Power continues to generate strong financial results and over the longer term, offers signature value creation upside for TransCanada. As efforts continue on the restart of Bruce on units 3 and 4, the four units of Bruce B continue to offer strong operational performance. Bruce has made a significant contribution to our power earnings thus far in 2003. On the pipeline regulatory front, TransCanada received the National Energy board's decision on the company's 2003 mainline tolls application in July.

In its decision, the National Energy Board approved the key components of our application. We're very encouraged that the NEB's recognition of our need to manage the long-term risks of the Canadian mainline. In Alberta, TransCanada, along with other utilities found evidence in the Energy and Utility Board's generic cost of Capital proceeding in July. In this application, TransCanada has requested a return on common equity of 11 percent, with a deemed common equity component of 40 percent. This hearing was set to begin in November. The EUB is considering the adoption of a standardized approach to determining rates of return and Capital structures for all utilities under its jurisdiction. At the end of September, TransCanada filed phase one of our 2004 Alberta System General Rate Application, once again with the EUB. This is first time since 1995, that TransCanada has filed a General Rate Application with the EUB for tolls on the Alberta system. From 1996 through 2003, we have been operating under various negotiated settlement agreements. The EUB hearing of the 2004 general rate application is set to commence in March, 2004. In reviewing the events of the third quarter, I would be remiss on not commenting on the August 14th, power blackout, while one of the most expensive blackouts in history. TransCanada's employees worked very hard under extraordinary circumstances to cope with the blackout and to work cooperatively with regulators and other utilities to get the power back on for many people.

Of note, we were able to keep gas flowing through our pipelines and bring almost all of our power facilities that did experience an outage back online within a matter of hours. As a result, the blackout did not have a material impact on TransCanada's earnings. Rather it was a compelling demonstration of the expertise, skill, and team work of our employees in Calgary, across Ontario and the Northeast United States in successfully managing a very challenging circumstance. As I noted at the outset, TransCanada's emphasis is on strong, ongoing financial performance, together with sustainable and value-creating growth that enhances shareholder value over the long term. Over the past three years we cultivated and continued to expand our portfolio of longer term growth opportunities. As opportunities have come to fruition in the near term, we've been able to capture and execute on the best of them. As developments in the third quarter demonstrate, we are well-positioned to act when the timing and the opportunity are right. I will now turn the call over to our Chief Financial Officer, Russ Girling who will provide additional details on our financial results. Russ?

Thank you, Hal and good afternoon to everyone. As Hal said we are pleased to report another quarter of strong financial results. As reported earlier today, Net Income for the three months ended September 30th, was $248 million dollar or $.51 cents per share. The results include Net Income of $50 million dollars or $.10 cents per share from discontinued operations.

As you may recall, in 2001, TransCanada substantially completed its exit from the gas marketing business; however, at the time remained contingently liable pursuant to obligations under certain energy trading contracts related to that business. As a result, the company deferred recognition of after-tax gains of proximately $100 million dollars on the sale of the Gas Marketing businesses in December of 2001. In June and July of 2003, the company mitigated its exposures related to the divested gas marketing businesses by obtaining from a subsidiary of Merit Corporation, certain remaining contracts and simultaneously hedging the market price exposures of those contracts. As of September 30th, TransCanada reviewed the provisions for loss on discontinued operations and the deferred gain, taking into consideration the impacts of Merit's filing for bankruptcy protection in July of 2003 and the mitigation of the liabilities I just referred to. As a result of this review, $50 million dollars of the approximate $100 million dollars after-tax deferred gain was recognized in Income in the third quarter. While we remain liable for certain residual obligations, we have concluded that the remaining provision is adequate and the deferral of approximately $50 million dollars of the remaining deferred after-tax gains relates to Gas Marketing businesses is appropriate. Excluding this gain, Net Income from continuing operations for the third quarter was $198 million dollars, or $.41 cents per share, an increase of $23 million dollars or four cents per share compared to the $175 million dollars or $.37 cents per share for the third quarter of 2002. All segments of the company contributed to the 13 percent increase in Net Income. On a Year to Date basis, Net Income from continuing operations was $608 million dollars or $1.26 per share, compared to $567 million dollars or $1.19 per share last year. The increase of $41 million dollars or $.07 cents per share was primarily due to higher earnings from the Power business and lower Net Expenses in the Corporate segment, partially offset by lower earnings from the Transmission segment. I will review the third quarter results for each of our segments starting with the Transmission business.

The Transmission business generated Net Earnings of $160 million dollars for the three months ended September 30th, 2003 compared to $154 million dollars last year. The increase is primarily due to TransCanada's $11 million dollar share of future income tax benefit recognized by TransCanada for Transgas to Oxidenta partially offset by lower Net Earnings from the Alberta System. The Alberta System earnings decreased by $6 million dollars in the third quarter of 2003 compared to the same period last year. The decrease is primarily due to lower earnings from the one-year Alberta System Revenue Requirement Settlement reached in February of 2003. This settlement includes fixed revenue of $1.277 billion dollars, compared to $1.347 billion dollars in 2002. The Alberta Systems 2003 annual Net Earnings initially expected to be $40 million dollars less than 2002 Net Earnings of $214 million dollars, are now expected to be approximately $30 million dollars below last year's results. The improved outlook for 2003 on the Alberta System is primarily due to lower operating and financing costs than we initially anticipated. The Canadian mainline Net Earnings increased by $1 million dollars in the third quarter of 2003 compared to last year. Earnings in 2008 reflected an increase in the approved rate of return on common equity from 9.53 percent in 2002 to 9.79 percent in 2003 and partially offset by a lower average investment base. And finally, with respect to our Transmission business. Our share of earnings from Investments in North American Pipeline ventures in the third quarter was $32 million dollars compared to $21 million dollars from the same period last year.

The increase was due to TransCanada's $11 million dollar share of future income tax benefits recognized by Transgas to Oxidenta. The tax benefits arose due to tax, which under Colombia tax laws increased tax pools. These benefits were not previously recognized. Transgas says it is likely that they will realize the benefits of the increases tax pools and therefore recognized as future tax Assets. Next, I will talk about Power. The Power business contributed Net Earnings of $50 million dollars for the three months ended September 30th, 2003, compared to $35 million dollars last year. The total volume sold in the third quarter 2003, was 7,410 gigawatt hours compares to 5,069 gigawatt hours in 2002. Earnings from Bruce Power, which was acquired in February of this year, was the primary reason for the increase. Partially offsetting the increase was the lower contribution from the western operations and higher general administrative and support costs. Bruce Power contributed $38 million dollars of pretax Equity Income in the third quarter. The Bruce B units ran at an average availability of 94 percent in the third quarter and TransCanada's share of the power output was 2,041 gigawatt hours. Approximately 34 percent of the output was sold to the Ontario market, with the remainder being sold under long-term contracts. Overall prices achieved during the third quarter for Bruce, were $45 dollars per megawatt hour. As highlighted in our quarterly report, on October 7th, Bruce A Unit 4 began producing electricity after performing evaluated tests of the shutdown system. Unit 4 is expected to reconnect to the grid and begin ramping up to full power. They are also working to remove the shutdown guarantees on Bruce A Unit 3.

Following the removal of the shutdown guarantees, Bruce A Unit 3 will undergo a similar commissioning test, and procedures as was conducted with Unit 4. Bruce Power invested approximately $80 million dollars in the restart program in the third quarter, bringing the total to $315 million dollars during the first nine months of 2003. To date, the cumulative cost by Bruce Power for the two unit restart is approximately $688 million dollars. Once complete, Bruce A Units 3 and 4 will add approximately 15 megawatts of low cost to the Ontario market. TransCanada's proportional share will be approximately 500 megawatts. Looking forward, Equity Income from Bruce will be impacted by fluctuation in spot market prices for electricity as well as overall plant availability which in turn is impacted by scheduled and unscheduled maintenance. To reduce our exposure to spot prices, Bruce has entered into fixed price sale contracts for approximately 1,850 megawatts of output for the remainder of 2003. As highlighted in the second quarter, scheduled maintenance began on Bruce B Unit 8 on September 20th, and is expected to continue into the middle of the fourth quarter. Turning now to the Western Operations. Operating and Other Income of $26 million dollars in the third quarter of 2003, was $14 million dollars lower compared to the same period last year. Lower prices realized on overall -- on the overall sale of Power in the third quarter of 2003 accounts for approximately $10 million dollars of the decrease. A significant portion of the western portfolio is contracted on a long-term basis, as contracts mature, we continually enter into new Power Sales Agreements at prices that reflect prices at the time the contract is signed. As a result, we can be impacted by the longer term trend in Power prices.

Although recent Power prices in Alberta are stronger than they were at the same time last year, they're still lower than prices realized in 2000 and 2001 when we first entered the Alberta Power market in a significant way. As a result, the average Power price realized in Western Operations in the third quarter was approximately 14 percent less than the prices realized during the same period last year. Also contributing to the decline in Western Operations was a $4 million dollar increase in the cost of natural gas fuel at the Cancarb Carbon Black Facility. Operating and Other Income from the Northeast U.S. Operations was $30 million dollars in the third quarter, which was $3 million dollars higher than last year. The increase is principally due to a 30 percent increase in the Power Production at our Curtis Palmer Hydroelectric Facility in the third quarter as a result of increased water flows. The TransCanada Power LP contributed $8 million dollars in Operating in Other Income in the third quarter, an amount comparable to that of last year. General administrative costs of $23 million dollars for the three months ended September 30th, 2003, were $6 million dollars higher than last year. The increase is due to higher support costs related to the continued growth of the Power business. Now let's talk about the Corporate segment. Net Expenses of $12 million dollars and $14 million dollars for 2003 and 2002 respectively.

The $2 million dollar improvement is mainly due to lower general administrative expenses related to services that supported discontinued operations. Now, I will turn to our Cash Flow Statement and to our Balance Sheet. In the third quarter, funds generated from continuing operations were $516 million dollars, compared to $467 million dollars for the same period last year. Funds generated from operations for the nine months ended September 30th, 2003, were $1.41 billion dollars compared to $1.36 billion dollars in 2002. Capital Expenditures excluding Acquisitions were $264 million dollars, on a year-to-date basis and related primarily to the Iroquois ongoing East Chester Expansion Project, maintenance and capacity Capital in the wholly owned pipelines and the ongoing construction of the MacKay River Power Plant in Alberta. Acquisitions during the first nine months of 2003 totaled $547 million dollars, and included the Acquisition of a $31.6 percent interest in Bruce, for $409 million dollars, including closing adjustments. The acquisition of the remaining interest in Foothills for $105 million dollars, and the acquisition of a 10 percent interest in Portland from DTE for approximately $19.3 million dollars U.S. or $25 million dollars Canadian. Including TransCanada has growth opportunities in its Pipeline and Power businesses during the first nine months of 2003. Looking ahead with the acquisition of El Paso's interest in Portland, we expect to invest approximately $200 to $250 million dollars in our core businesses in the fourth quarter bringing the total to approximately $1.2 to $1.3 billion dollars for the year. Our Balance Sheet remains strong, comprising of 58 percent Term Debt, 4 percent preferred securities 2 percent preferred shares and 36 percent common equity. The company's discretionary cash position also remains strong as they expect to generate substantial Operating Cash Flow. To summarize, the company's Net Earnings and Cash Flow, combined with a strong Balance Sheet continues to provide TransCanada with the financial flexibility to make disciplined investments in its core businesses.

As we said on numerous occassions in the past, we will continue, as we have done in the past four years, to make prudent investments of our discretionary Cash Flow and make profitable investments in Natural Gas Transmission and Power, but be assured that our evaluation approach will remain disciplined and focused to ensure we continue to enhance shareholder value. We will continue to work on establishing a new regulated business model that provides value for our customers, reduces the long-term risks of our Canadian pipelines and allows to us earn competitive returns. We will continue to focus on operational excellence, with a focus on providing low cost, reliable service to our customers, and we will continue to maintain a strong financial position and will not compromise our credit ratings. Success and the execution of these strategies has and will continue to result in earnings in Cash Flow growth and build value for our shareholders in the future. That concludes my prepared remarks. I will now turn the call over back to David.

Thanks, Russ. Just before I turn it back to the conference coordinator, a reminder that during the question and answer period, we'll except questions from the investment community first and that will then be followed, we'll then provide an opportunity for the media to follow. And with that, I'll turn it back to the conference coordinator.

Thank you Mr. Bennetta. We will now take questions from the telephone lines. If you have any questions please press the star one on your telephone keypad. If you are using a speaker phone please lift the handset and then press star one. If at any time you wish to cancel your question, please press the pound key. Please press star one at this time if you have a question. We'll have a brief pause while the participants register. We thank you for your patience. The first question comes from Matthew Akman from CIBC World Markets. Please go ahead.

Thanks. I guess this is for -- maybe for Hal. You know, you guys have announced a lot of new projects in the past while, the Beck and Core [phonetic] and then the Irving, the Cherry Point Plant, LNG Facility in MacKenzie, but not much in the way of Acquisitions. I'm wondering if from a strategic standpoint, based on what rating agencies are doing and the acquisition environment that it's better to build than buy, and sort of throw in the towel on acquisitions.

Well, in fact, Matthew, we've announced some big acquisitions of both the partner interests in Foothills and the partner interests in Portland which do add up to a fair bit of investment there. We're not avoiding acquisitions in any way. We continue to pursue them. We submit proposals on many different situations, and to of the extent that we're able to do deals that meet our criteria, we'll go ahead, but as I said before, we're very loathed to pay too much to acquire Assets.

Absolutely we're interested in acquisitions. We keep working on them. We just happen to have a lot of very interesting grass roots or I might say Greenfield opportunities available to us right now so that if we're not succeeding on the one front, we have the other one to turn to and I think in the year 2003, we've accomplished some very good things on both fronts.

And just to add to that you know the numbers actually, Matthew, this year, we've spent, you know, close to a billion dollars in the first nine months and with the close of the last part of the Portland transaction with El Paso it will be in excess of $1 billion dollars on the year. Our strategic intent is to spend the free Cash Flow on good opportunities, and most of that has been in the acquisition sector in things that have sort of what I would call visible earnings attached to them, being, you know, for the most part about, you know, 4 to $500 million for Bruce and 4 to $500 million dollars, almost $600 million dollars in Power -- or in Pipeline opportunities.

Okay. Thanks for that. Can I just in one different area, obviously it's a great quarter, you guys are having a great year. I don't mean to pick on any of the weaknesses but the Western Segment does stand out. And, you know, I know, Russ, what you said about Power prices being down, but it also looks like sales aren't up a whole lot year-over-year despite the addition of Bear Creek and ManChief and also the availability looks like it's down to to 91 percent from 98 percent year-over-year on the quarter. I'm wondering if something else is going on there, I guess, other than prices being down? And number two, is there maybe some upside next year because Power prices in Alberta were so much higher this year than anticipated?

I guess to answer the first part of the question, it is mainly due to price, but maybe I will ask Lee, is there anything else in there --

One thing would be the availability that I think we've had a lot of new plants in the last couple of years that have come on. For as much of the time we would have expected being start-ups, between that and the prices, I can't think of anything else.

Okay. And the other part of my question, upside next year because of higher power prices this year?

Again we continue to follow sort of longer term trend in prices to the extent that prices are trending upwards and we are recontracting our portfolio going forward on higher prices you can expect us to sort of follow that longer term trend.

Okay. Thanks very much.

Thank you, Mr. Akman. Our next question comes from Maureen Howe from RBC Capital. Please go ahead.

Thanks very much. Just continuing on in Western Ops.., the $4 million dollar increase in gas costs at the Carbon Black Facility, can you, again, just provide some more light on that, and to what extent do you hedge those costs going forward? Do they float and what sort of sensitivity would be -- should we expect to see? It seems like a big number.

It is a big number. You know, Natural Gas is the single largest, you know, input cost to running the Carbon Black Facility and at various times we do attempt to hedge it but for the most part, the output from the plant, the Carbon Black, isn't attached to natural gas prices. Therefore hedging can get you into trouble as well. We continue to float more with market and that's been the market impact that we've got of the rising natural gas prices in the quarter.

Let me just make -- did you say that Carbon Black isn't -- doesn't correlate with that natural gas prices?

Maureen, it's Hal here. We found on a rolling forward basis we are able to flow most of the extra costs through to customers but it doesn't happen within the current week or the current month.

Okay well, I guess I'm not understanding that. I mean, just in -- if they don't -- if they don't flow with natural gas prices and they are not correlated, it seems all the more reason to hedge those gaps. I'm confused.

I guess it depends on how long a term forward you are hedging but, you know, I hear you on that. One of the things, though, that we looked at in the Carbon Black side is that we want to be able to be pretty responsive to the market, and our -- our view is that over, you know, a two or three-year period there won't be a whole lot of difference in our average cost of gas either way.

Okay. Okay. That's -- and so what sort of sensitivity do we see from that facility then, you know, given say a $1 change in the price of gas?

I don't actually have that -- I don't know if you have a sensitivity like that. That's something that we can get back to you on, though, Karen.

Maureen.

We can get back to you on that. We'll work out a sensitivity for you.

No, that's great. Thanks. And the -- on the Alberta System, field receipts were down during the quarter. I'm just wondering what you guys were seeing and if there's any reason that you can actually identify as the reason for the decline?

Well, it's -- Maureen, it's a whole mix of things that we have trouble analyzing sometimes. Sometimes, it's due to incremental volumes moving through other systems. For example, if Alliance has resolved some of the compressor problems they had a year ago, we see that taking some volume off of our system and similarly the movement back and forth between our pipe and the Duke pipe in BC.

But these fluctuation tend to get amplified and become more obvious when the overall production is basically flat. There's really no aggregate growth out of Western Canada so that any movements, instead of in the old days they would have shown a flat, today they actually show a decline. So there is, in fact, a decline on field receipts into our system, and I couldn't be any more precise than to say it is the combination of flat overall basis in production and some movement back and forth between the three main pipes.

Okay. That's great. Thanks. Russ, you ran through what triggered the tax benefit for the higher tax benefits pretty quickly on Transgas. I'm wondering if you can go through that once more?

I think I will let Lee do that one. Did I go through it quick on purpose. [ LAUGHTER ]

So, Maureen, in Colombia, the tax laws allow to you have some index base adjustments that help in your current tax years but do you end up paying some tax on that as well and the index adjustments basically increase the taxes which you can use in future years. On that indexation adjustments, which are upward adjustments --

What is an index adjustment?

An inflation adjustment.

Okay.

So basically when those indexation adjustments are actually put through the account for tax purposes, there is actually a tax that is attached to that that you pay and then the view is that -- it's a refundable kind of tax. So that when, sometime in the future, when you're able to use that indexation, you will actually get money back, basically.

Okay.

Is what happens and so what they've done in the past in Colombia. It's a relatively new pipeline is that they've paid these under the law but because they haven't been sure, or not even sure, at least somewhat likely that they will collect them in the future, they haven't actually recorded that benefit now, which they could as a deferred tax because they would -- they have not been comfortable to do that since start-up. Start-up has now been a few years ago.

They have become confident, my management as well as the auditors, because this was an audited number that we got, that, in fact, in the future they will be able to realize on those amounts. Their contracts are getting better, tolls are going up. Everybody performed to date. They have collected their tolls. They are confident that they will be able to realize that money.

Mm-hmm.

And so because they could have been recording the benefit but have not been, because they haven't been confident, what has happens is when you are confident, you basically record a one-time item to do that.

Okay. Okay.

They did that and we simply picked up our share.

Okay. That's great. Thanks. If I could just ask one more question and it has to do with some -- the Bruce contracts. You do make the statement, and you make it in the written document, as well as, Russ, you made it verbally, that through reduce the exposure at the Bruce Plant you've locked in 1,850 megawatts for remainder of 2003. Now it strikes me that that was pretty similar to what was there at the beginning of the year, maybe a bit more, but sort of in the ballpark. I'm wondering have there been new contracts that have been entered and if so, is the average price still $42 dollar or has it moved from there?

It hasn't moved substantially, Maureen, the number is the same. We haven't gone out to contract, you know, any of Bruce A until we are confident that Bruce A is going to perform. So we're at what is the prudent level of sales, given our current comfort with output.

So there have been some new contracts entered then?

Nothing material.

Nothing material.

In terms of changing averages and things like that, there is not anything that would change the average prices or anything like that.

Okay. Thank you very much.

Thank you, Ms. Howe. The next question comes from Andrew Kuske from UBS. Please go ahead.

Thank you. Good afternoon. A question for you on the Ontario Power market with the new government that's just been announced or actually they took power on Thursday, a question for you on your outlook in Ontario and particular there's some speculation that we might see a revival of the old NUG contracts would you be interested in those contracts? What is your preference? Do you prefer to see a free open market? I will really leave it at that for starters.

Okay. It's Hal here. We don't have a strong preference for one kind of market structure or another. What I've said before is that we just very much like to see clarity in the ground rules and a stable arrangement. We're very happy in Quebec. We building a plant like Becancour and entering into essentially a tolling deal with HydroQuebec. We think that's a good arrangement and predictable one and we were quite happy operating in the Alberta market where there's a strong commitment to letting market forces work. We'd like to see some clarity one way or another in Ontario, and we'll just observe that if the market is going to be a free and open market, that the Ontario government still needs to decide what to do about Ontario Power Jam and the dominant position they have in the marketplace there today.

So it's too early to say, in my view as to what's going to happen in Ontario. We're committed to that marketplace for the long term. We have significant investments in Ontario, and we will be, you know, expressing our views to the Ontario government, but the number one thing we would like to see would be some clarity, as to what the market structure and the market design will be.

Okay. So with increased clarity, whether it was clarity in having long-term PPAs or NUG-type contracts or just a free and open market you would like to have some further investment in Ontario.

Yes, I think we could generally say that. We plan to make further investment in Ontario and the only thing that would dissuade us is if it was not a clear market, and end of story. If it's flip flopping back and forth that's obviously not something we'd like to see.

Okay. Then if I may ask a second question completely different topic, in particular, as it relates to northern development, how do you see the issue of Aboriginal title really unfolding? There's been some issues that have come in lately into the main stream media, just on potential issues with some of the Aboriginal tribes and nations. How do you see that being resolved?

I don't know how it will be resolved, but my observations would be this way: Firstly, we've worked hard to strike an arrangement with the Aboriginal Pipeline Group, which gives the Aboriginal people of the MacKenzie Valley the right to take ownership in the project and we think that's a very valuable arrangement we put together for them and we look forward to working with them to make that a reality.

At the other end of the spectrum, in each community, the proponents of the pipeline need to reach benefit agreements with the local communities and with all the people that are members of those local communities, and that is a much more detailed exercise, and one that the project team led by Imperial Oil is currently working through. I think the benefits are large and significant and well-appreciated by the Aboriginal communities in the valley and I think in recognition of that, they will continue to work constructively to try to get this whole thing put together. We just were very -- we're very much inclined to do anything we can to help that process along. We think our support for the Aboriginal Pipeline Group initially was a major step in that and we're also helping out in discussions at the local level where the different parties want to us do that. So I remain optimistic, but one shouldn't understate the challenge of getting so many different parties together on the same page to enable us to go ahead. We look forward to going through that as quickly as we can and getting on with the value creating work of installing and starting up a pipeline.

What do you see the next phase in the whole pipeline process?

I think the next major milestone step is the filing of the formal project applications in the first quarter of next year.

Okay. Thank you very much.

I -- I apologize a little bit for being vague on some of those things but as you can appreciate, there's a lot of uncertainty as to just how all of the different pieces will come together and when that will occur, and I just say we continue to work hard towards that formal application in the first quarter of next year.

Thank you.

Thank Mr. Kuske. The next question comes from Karen Taylor, pardon me, from BMO Edward Burns. Please go ahead.

Thank you. I wanted to thank you for the extra disclosures this quarter with respect to Bruce. And I just have a couple of questions to clarify and then a couple of other questions for Bruce. I just wanted to make sure that the interest costs that are expensed by Bruce, but Capitalized by Trent Canada are about $4 million and maybe that's for lease?

You're absolutely correct, Karen.

Okay. And the Amortization of both the purchase price discrepancy and out-of-money contract within each specific year, you have given us the amount, I'm assuming that on a quarterly basis that would be a straight line; is that correct?

Yes.

Okay and just with respect to Bruce, when will the unit or when is the unit from your point of view, accounting point of view, technically commercially in service? Is that the point at which we synchronize the grid? Is it at 50 to 60 percent of NCR? When do you deem it in service from an accounting point of view?

It is Lee here. We look to the commercial size of it, the technical side of it as to when things are on the grid when they think they are stabilized, when they believe that, obviously from an accounting perspective that we are covering all of our costs but really it comes down to stabilization on to the grid. We believe it's relatively permanent that it's in place and that we're covering our costs at that point, we would transfer from capitalization of those amounts into reporting of revenue.

Okay. Just a couple more questions of that nature, if you don't mind. The total estimated cost, we said at the end of September was about 688 to restart Bruce. If I do the math, based on the previous calls, we're looking all in to be 748 to 750 to restart the reactors in total? Is that in the ballpark?

Again that would be a number that we haven't put into the marketplace. I think we were 688 to the end of September. We spent about 80 in the quarter. We were down to a run rate of, you know around $30 million dollars. The $35 million dollar for the two reactors, we're below that now in terms of a run rate. Costs have gone down considerably, so right now we have not put out a number, other than 688 to date, and our run rate is probably down, you know, something less than it was before in the, you know, 15 to $20 million dollar range.

Okay. And at what point do we expect to see the equity earnings translate or some, you know, Cash Dividend, if you want to call it from Bruce? When would those begin?

Again, we haven't talked about Cash Dividends. It's something that, you know, we have to sort out with our partners in terms of distribution policy, and that, you know, is -- has to be considered with the budget next year, where we think the prices will be and what the 2004 Capital Expenditure program looks like. We haven't determined that yet but it's something that, you know, as a partnership we're working on right now.

Okay. And just related to the Capital Expenditures. Do you have a maintenance schedule that you can make available for fiscal '04?

Not yet. Again the people of Bruce are still working hard at that. Obviously with the delays if the Bruce A restart, and those types of things it changes our schedule for next year.

I think our view of -- on a go-forward basis is still the same for 2004 in aggregate, it's somewhere around that at 80 percent availability for the plant as a whole, but how that gets stacked up, and obviously there's planning around, you know, different times in the market, different hours on certain equipment, and prices in the marketplace, and when we think it's most appropriate to take these facilities down for maintenance. So we're still shooting in around the 80 percent for 2004 that we've talked about.

And that would be for all six reactors?

Yes.

And just to add, that's pretty much consistent with what we saw in the December presentation that we provided when we made our first a -- first announced our investment in Bruce.

Mm-hmm. Just wanted to confirm. That and very lastly on the operating cost side for the fourth quarter, we've seen that the costs on an operating basis at Bruce are fairly consistent. Sort of in that 180 to $200 million dollar range. When we have all of the reactors operating or transition to that in the last quarter of the year, where will costs be? Are they going to be -- I guess I'm trying get a grip on where the number is likely to shake up in view of the fact that we're sort of in transition this last quarter.

I think consistent with Russ's comments, Karen, they're still working through the budget process, but obviously, they will trend upwards, probably something less than 50 percent, but -- but I wouldn't put them materially less than 50 percent, but that's probably the best we could provide at this point. 50 percent increase, IE, go from four to six reactors and the operating cost would go up about 50 percent.

Okay. I'll get back in the queue. Thank you.

Thanks, Karen.

Thank you Ms. Taylor. The next question comes from Linda Ezergaylus [phonetic] from TD Newcrest. Please go ahead.

Just to further the question about the Capitalization of Interest Expenses, I'm wondering what the total amount capitalized was? I'm assuming that you are capitalizing some of the Interest Expenses from MacKay River?

The answer is yes, and --.

The answer is yes and not very much but we're getting it.

Okay. So --

So it would be a pretty small amount, Linda, but we'll get that before the call is done. It's a big number, though.

And MacKay River is in service when?

End of this year, end in the first quarter of next year.

Okay so late Q4, early Q1. Okay. And the $110 megawatts contract with the OESC that commenced on August the 10th, any indication as to whether or not it will be extended to April the 30th and can you share with us if it's kind of some sort of a availability contract, is it an actual output-based contract or can you share that with us?

I think what I can tell you is that -- this is my understanding that it's a capacity contract. It's, you know, insurance capacity in the marketplace. I can't tell you for sure whether or not -- if the contract has been extended. As far as I know it hasn't but that's something that we can get back to you on, Linda.

Okay.

Linda?

Yeah.

You were asking about the MacKay River interest capitalization, it's about five year-to-date and about two in the quarter.

Okay so then four plus two is six million capitalized total for the quarter?

Four on Bruce. Yes, and that would be a pretax number.

Okay. Pretax. And then use a marginal tax rate on that?

Yes.

And there's nothing else that I should be aware of that would be --

Loan interest. Nope.

Okay. Thank you. I will get back in the queue.

Thank you Ms. Ezergaylus. The next question comes from John Edwards from Deutsche Banc.

Yes, good afternoon. This is Deutsche Banc. Just a couple of questions - could you explain a little bit more in detail the purchase price amortization of the Power Purchase Agreement for Bruce? I wasn't clear how that worked.

Are you referring to the -- the unamortized amount open the purchase price, John?

I believe that's -- I mean, it was what caused the - we were projecting your -- $31 million for our, you know, contribution and it came in at $38 and it looked like the big piece there --.

Yeah that's the same one.

Yeah.

Okay. The accounting for that on an acquisition, you have to look at all of our Assets and Liabilities and fair value them. In the case of this acquisition, we fair valued the -- the Power Purchase Agreements that Bruce held at the time. There was a negative mark-to-market on that, or negative fair value, I should say of $131 million of negative fair value. For accounting purposes, you bring that into income no different than you would if it was a plant or any other Asset or Liability of that -- of a similar nature.

So what we looked at was when do those underlying contracts fall off and what is the value, the fair value of each of one of those? We then took the $131 million, took it over the life of the underlying contracts which was about five years, came up with the numbers that we disclosed in the financial statements, in the note, and simply took the fair value, added them up. They came up to the $131 million. We then amortized those amounts on an annual basis as per the schedule. We -- we straightlined them as someone said over the 12 months of that particular year, and it becomes an increase to income when they are amortized because it was a negative fair value. And it's -- that's the accounting.

Okay.

If it had been a positive fair value, it would have gone the other way.

Okay. Great. And then in terms of -- Bruce A, when that's going to go online, maybe you said it and I missed it. Bruce A Units 3 and 4, when do you expect that to -- to be fully connected to the grid?

Again we did synchronize to the grid October 7th, I think that's what we did say, and then as part of that, it's -- there's ongoing testing. We did take the facility down to make some minor repairs, and are working now again on getting it back -- back online to the grid. We would expect that in the next few days There's a -- we ramp up to 50 percent power and then there's an emergency shutdown test that takes place. Once we're through that, then we'll begin to ramp to full power. You know the time frame for that process, you know, we would expect in the next little while.

By December 1st, say?

Again, given the uncertainty of the process, you know, this is sort of new, you know, sort of -- we haven't put a pin in that date yet, John. So what we're doing is we're just sort of going day by day right now and managing the issues as they arise.

John, it's Lee here. If I could just add to my comment, that negative value should also realize that that played into the amount that we paid for Bruce. That reduced the amount of initial costs that we did end up paying for Bruce. So you do get the cash value through the -- through the accounting.

Okay. Great. And then what do you expect over -- or what percent of the total market then is Bruce to the Ontario power market and, you know, what do you expect that to do on the spot power prices and also comment how much -- yes, you did comment a little bit how much you expect to sell forward, but if you could give a little bit of comment of how you expect to impact the Ontario Power market that would be great.

I think it totals, about 15 percent of the market, and in, you know, obviously increasing supply in the marketplace has a negative impact on prices. That's built into our -- into our sort of forward forecast of prices, but I think as Hal pointed out as he was talking about the Ontario market, you know ,there is a large player in this market being OPG, which really has a large influence on what prices are going to be. So our power being in the market, I guess I would -- my view is that it's not significant one way or the other in terms of impact on price but the prices are driven by, you know, many other factors, including our Power but the other influences are probably greater than our Power.

Just to clarify for you, Russ had mentioned the 15 to 20 percent of the Ontario market. That 15 to 20 percent is for the entire six units, not just for the two coming on, just so you're clear on that front.

Thank you very much.

Our next question comes from Mr. Donatulebay [phonetic] from Royalist Independent Research.

I just wanted to say that the NEB was thinking of coming up with a generic equity component or something there. I just wonder, you know, historically TransCanada has not been treated that fairly historically on an equity basis. Do you sense that is changing? And I also wanted to find out. I think you said your common equities approximately 36 percent, I was going through the numbers myself and I didn't know if that included the $824 million or so that was nonrecourse financing. I think it was $803 million. Or not. And that figure you came up with, did that include the preferred as well? Thank you.

Yes, Hal here. I will answer the first part of your question and then ask Russ or Lee to comment on the second part. We've got -- we've made applications for thicker equity to the Energy and the Utilities Board in Alberta in their generic return here and we've suggested that 40 percent equity thickness would be appropriate for an Asset of that risk profile and similarly on the main line, which is regulated by the National Energy Board, we have been suggesting thicker equity. It's difficult for to us predict where the equity thickness will end up on either of those two systems but but we certainly made our views known to both customers and the regulator on the changing risk profile of those Assets. Lee, or Russ, do you have a comment on --

With respect to your second question on the Balance Sheet, the 36 percent or so with just common equity and that's on an equity accounting basis, it didn't include the -- the nonrecourse debt that you're referring to. In addition to that number, it doesn't, as well include above 4 percent preferred securities and 2 percent preferred shares. So the way we look at it is sort of 38ish percent equity with 4 percent, you know, preferred securities and then the balance being debt.

Okay. Thank you so much. I appreciate it and good luck with that higher equity.

Thank you.

Thank you. Our next question comes from Andrew Fairbanks from Merrill Lynch. Please go ahead.

Hey, good afternoon, guys. I wanted to explore the Western Power Operations a little bit more as well. You indicated that with some of the contract expirations that effectively the pricing is rolling down to market prices. Is it right to say if we have similar prices to the third quarter levels we'll see a similar $26 million dollar run rate in the earnings for Western Power Ops.? Or are there some other twists and turns in there that we should be aware of?

Besides other twists and turns and all things being equal, I think that's fine, at least into the next quarter.

That's fine. Great.

Can I add one thing to that. In our Western Operations, the price of Power in Alberta is getting pretty close to the price of gas. To the extent it is Power coming from our Coal-fired Operations, the margin will widen and contract as the price of gas goes up and down. In our substantial co-gen operations in the west, we have a heat rate advantage that gives us generally a better margin to the gas market.

And actually do you have just a rough split between, you know, fixed or formulaic prices rather than what would be moving with spot prices be it natural gas or some other index.

The biggest impact will be the shape of our forward sales and how much Power we sell forward and that's difficult thing for to us predict for you, because that -- that varies within the year and from year to year.

Okay. Great. Thank you.

Thank you Mr. Fairbanks. The next question comes from Maureen Howe from RBC Capital Markets. Please go ahead.

Thanks very much. I just had a couple of follow-up questions. Starting with Power, it looks like in the Northeast, the financial operations seem to be a little better than I might have anticipated and particularly in light of the expiration of the gas contract at Ocean State. Is that the improvement, is it all Kurtis Palmer or have there been any positive developments at Ocean State?

No, Ocean State is status quo. The largest portion of the increase is Kurtis Palmer. They are scouring over the numbers to see if there's anything else bumping around there. The status of the gas contract is unchanged from our last disclosure.

Okay. And then just with respect to the cost of Power - on page 6, where you have it broken out, the costs have increased there by $6 million, and then in the segmented note, it -- other costs and expenses are actually up $18 million quarter-over-quarter, are these -- what are these? Are these development costs or are they? What kind of costs are these?

Your first question, Maureen, are you looking at page 6?

Yeah, the 6 million -

General administrative and support costs?

Yeah.

So they are Maureen, it is Hal here, the costs of running the business, plus a share of general corporate costs within TransCanada, plus a significant part of it is that we're growing this business and we're always expensing development costs on projects that are not yet in the bag. Later on in the cycle of that project, those costs will be capitalized, but at the early stages we expense them. And if nothing is done within the current year, they remain that way. So that's really the best explanation I can give you of those three categories.

Okay. And then just one final question and it has to do with foreign exchange. You reference foreign exchange a couple of places throughout the interim, and I'm wondering if you do have a total impact during the quarter from, you know -- a total FX impact quarter-over-quarter?

We do. It is not as big as you might think, Maureen, because there's offsetting amounts.

Mm-hmm.

I think where we do mention it, we mention it probably in the Power Disclosure, Power Income being lower, as well as our North American pipeline ventures being lower. It's offset by hedges at the corporate level, so the -- the impact of changes in foreign exchange are -- are minimal on an aggregate basis.

Minimal like a cent? or --

Maureen, I would say for the nine months, it's probably just over a cent.

Okay.

For nine months.

Okay. That's great. Thank you very much.

Thank you, Ms. Howe. The next question comes from Karen Taylor, BMO Nesbitt Burns. Please go ahead.

I just had a question quick on the Alberta system. Year to Date performance is albeit down versus '02 but it is better, and you certainly revised the number upward. Is that because you have, at this point -- I don't want to use the word overfunded the equity but I noticed -- and I don't know if it was the GRA or the evidence on the generic hearing where you have 38, 39 percent common equity allocated with this pipeline and plan to have over 40 percent by year end. Is that because you're paying down debt in advance of the hearing or prefunding equity or something?

I guess the first part of your question is it has nothing to do with the -- the income side. The income side is really related to lower financing costs, as we said. With respect to to the equity thickness inside of the NGTL system, obviously that's been a growth over time. We haven't artificially wrapped that up. As we said to the regulator, our belief is that what is required to operate that business is 40 percent equity and applied for 11 percent on 40, but we didn't ramp that up in anticipation of the hearing or anything like that. That's where our aggregate equity is on the Balance Sheet is, and we've talked about that before.

And there's probably more equity in our regulated business than we get credit for from our perspective. So as we said from before, there is a cross subsidation from our regulated business -- or from our nonregulated business to the regulated business, essentially the shareholders subsidizing the shippers on the pipeline system because we're not getting paid for that equity today in the revenue requirement.

It's Lee here, Karen. Really, it's just related to lower costs that we are at risk for under the settlement that we have derived in 2003, sort of all the costs that we're at risk for. It's really just lower than what was in the settlement. That's all that's driving it.

Sorry. The two-part question, that -- from your answer, the first one is then if this is a one-year settlement, we're heading into a full GRA for '04 and I know the board has expressed a preference to assess, if you excuse me, the total Capital requirement and return on both the NOVA System and the Adco Pipelines in the same year in order to better assess the competitive situation. How sustainable is the Year to Dae results in the Alberta System going into '04? And then secondarily, if the shareholder is subsidizing this regulated book, then it presumes that you are undercapitalizing or you don't have as much equity on the power book as we would assume and then what would be the corporate and allocated interests? Sorry, that's three-parter.

I think you've sort of gone deeper. What exists at the corporate level we've talked about before on an aggregate basis is the 36 percent common, 2 percent preferreds. What we said before is if you take the deemed amounts of equity that we're allowed in our regulated businesses, you achieve a number of -- you know, having excess equity in our nonregulated business.

As you move down into terms of how we allocate it, inside the businesses, I guess in my view, it doesn't suggest we're understating or overstating, you know our equity in the Power side of the business. What the rating agencies look at, they've been pretty clear at this, if you look at the overall equity thickness of the business as whole, not how we allocate it internally, but it is how we maintain it overall, at the corporate level, not at the subsidiary level and not at the power level.

Okay. So what is the unallocated financing costs at corporate? And how much debt is there?

The - Karen, I don't have that right here. We'll do an analysis and we'll get back to you. I simply don't have that right here.

Terrific. Thank you.

Thank you, Ms. Taylor. Our next question comes from Matthew Akman from CIBC. Please go ahead.

Can you -- still on the Alberta System, can you talk for a second about how you see them looking at TransCanada, the Alberta System, vis-a-vis some of the other utilities in Alberta, and, you know, you've applied for 40 percent equity and 11 percent ROE. Some of the recent decisions on utilities are obviously lower than that but they are allowing higher ROE for pipeline business. How do you see that resolving and can you separate yourself from some of the other utility businesses and be treated distinct from those because of the competitive factors?

Matthew, it's Hal here. Two issues - one is the equity thickness and the other is the ROE. I'm not sure that the EUBC's pipeline is deserving a higher ROE than anything else, maybe that's true in one case or another, but generally, the -- the attitude of the EUB seems to be towards some kind of generic ROE that's certainly the driver of the hearing that they've -- that they've kicked off. And our objective in all of that is to continue to argue for fair and competitive ROEs that are competitive in the larger financial world, not just within the province of Alberta, and we'll be continuing to make the point.

We have many other investment opportunities besides just within the province of Alberta. So the -- the other question I think, though the more interesting one is why does the EUB take the position it does on equity thickness? It has concluded in the past that some other kinds of business like local distribution companies are riskier than pipeline businesses and therefore deserve thicker equity and some pipelines have been riskier than others and it's not necessarily clear to us why that is. So we're being -- we're focusing on the equity thickness argument to a significant extent and trying to have them look at all of this in a more accurate, relative sense, and try to argue for a thicker equity, which we believe we should have in larger competitive world.

So it's your view that you will probably end one the same allowed ROE as everyone in the province?

I don't know that, but I -- I would not conclude that and I wouldn't argue for that but I would say that would not be an unreasonable conclusion for you to reach.

Okay.

The -- you know, I think the important part for us is we haven't been in front of the regulator on this issue of equity thickness, I mean, in comparative risk since 1995, and from our perspective, there's been, you know, significant changes in the environment that NGTL competes in since that time, and that's what we would hope to highlight to the board relative to where, you know, the ranking of comparative risk were in 1995.

And if I could add one last footnote to it, in recent -- in the past couple of years, both in Alberta and on the mainline, we and our customers and our regulators have moved away from multi year incentive arrangements and we think that's counterproductive. We made some great advances in reducing our costs during the period where we had multi year incentives. We would like to work towards three to five-year incentive arrangements on both the Alberta system and the mainline and I know that a significant number of our customers would like to do that as well.

So that we'd be given a certain defined allowance for our costs and then we would take some risks but also have significant upside if we could drive costs out of the system and extending that from just OMNA costs and if we were able through astute moves to reduce the amount of fuel we consume -- the amount of fuel we consume to move a certain amount of gas, we would very much like to be able to work towards that. And I'm optimistic that maybe not this year, but in the years ahead, we'll get back into those multi year incentives with our customers.

Okay. And one last, very specific question on the Cash Flow Statement for this quarter, can you explain the $168 million deferred amount that shows up there? As a cash outflow?

I can't but maybe Lee can.

Oh, here it is. Sorry. Wrong one. The $168 million? Just one second. I can't. I just can't find my piece of paper. We will get that for you. Hopefully if we have it before the call concludes we'll relay it, if not I will give you a call and follow up.

Okay. Thank you.

Is that okay?

Thank you.

Thank you Mr. , Akman. Our next question comes from John Edwards from Deutsche Banc. Please go ahead.

Yes, just a follow-up. You know on the Western Power Operations, you know, maybe you already addressed this somewhat, but, you know, it did -- you -- you explained that it was lower on lower power prices and I guess the question is, you know, why point to lower power prices? We were thinking most of that power was sold forward. I mean -- so maybe a little bit of it has to with the mix between spot versus what was sold forward there?

Right. We have a series of contracts, you know, some short term, some long term, this would be the shorter term contracts that we're renewing now that we originally sold, you know ,the first couple of years forward when we bought this - bought the PPAs, we sold it forward at substantially higher prices than we are renewing today.

There's still a good chunk of the portfolio that is out for a longer term and it's still enjoying better prices, but this will be the shorter end of the portfolio, and what we try to do is continue to, you know, make sure that in the current year, that we have the majority of the power sold. So -- but there's a continuous rolloff of, you know, one, two, three year contracts in that portfolio but they are still in the portfolio, some longer term contracts as well.

And so John, the prices, I think would be fair to say they are higher today than they were a year ago but not as high as they were two or three years ago.

Okay. Thanks.

John? Yes. On your --

Oh that was Matthew.

Sorry. Move on. My mistake. I was going to -- Do you have it? You might as well answer it.

Are you there Matthew? Lee does have the answer and I will read the Cash Flow Statement.

The $168 million, almost 90 percent of that are simply changes in the regulatory deferrals on the Alberta, the mainline and the BC system. And it makes up 90 percent of that number.

Now, John Edwards, did you have another question for us?

No, I think you -- you covered it. Thank you very much.

Thank you.

Thank you Mr. Edwards. So this concludes the financial analyst question session. We now take questions from the media. If you have a question, please press star one on your telephone keypad. If you would like to cancel your question, please press the pound key. At this time, our first question is from Mr. Chris Donville from [inaudible] news.

I don't know if you covered this earlier but I'm wondering when you expect to take the other half of the your deferred gain from the sale of the natural gas marketing business?

We -- we assessed that on a quarterly basis to determine, you know, the -- the risks and the exposures that we have and the appropriateness of the -- of the provisions that we hold, including the deferred gain. So like, you know the balance of our portfolio of discontinued operations we review that quarterly and we assess it at that time. There's no sort of set date or time that we plan on releasing that. It's done on a quarter by quarter assessment.

Okay. Thank you.

Thank you sir. At this time there are no further questions. I would like to turn the meeting back over to Bennetta.

Thank you very much for participating, to all of those that were listening today and we look forward to talking to you again in the not too distant future. Bye for now.

Thank you Mr. Bennetta. The conference has now ended. Please disconnect your lines at this time. We thank you for your participation and have a great day.