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Executives

Lee Evans – Manager, Investor Relations

Steve Becker – President and Principal Executive Officer

Sandra Ryan-Robinson – Principal Financial Officer

Stuart Kampel – Vice President and General Manager

Analysts

Gabe Moreen – Merrill Lynch

Michael Cerasoli – Goldman Sachs

John Tysseland – Citigroup

David LaBonte – Kayne

TC PipeLines, LP (TCLP) Q3 2011 Earnings Conference Call October 27, 2011 12:00 PM ET

Operator

Good day, ladies and gentlemen. Welcome to the TC PipeLines, LP 2011 Third Quarter Results Conference Call. I would now like to turn the meeting over to Mr. Lee Evans, Manager, Investor Relations. Please go ahead, Mr. Evans.

Lee Evans – Manager, Investor Relations

Thank you, operator and good day, everyone. I’d like to welcome you to TC PipeLines third quarter 2011 conference call. I am joined today by our President, Steve Becker; and our Principal Financial Officer, Sandra Ryan-Robinson, and as well Vice President and General Manager, Stuart Kampel.

Please note that a slide presentation will accompany the remarks, which is available on our website at tcpipelineslp.com, where it can be found in the Investor Center section, under the heading, Events & Presentations.

Steve will begin today with the review of TC PipeLines third quarter results. Following that Steve will provide an update on the activities concerning the Partnership and its sponsor, TransCanada Corporation. Sandra will then proceed to review in more detail our financial results for the third quarter followed by Steve returning to provide the wrap up of the quarter and to leave you with some key messages. Following the prepared remarks, I will ask the conference coordinator to coordinate – conference operator to coordinate your questions.

Before we begin, I’d like to remind you that certain statements made during this conference call will be forward looking regarding future events and our future financial performance. All forward looking statements are based on our beliefs, as well as our assumptions made by and information currently available to us. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties, and assumptions as discussed in detail in our 2010 10-K, as well as our subsequent filings with the Securities and Exchange Commission.

If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, actual results may differ materially from those described in the forward-looking statements.

With that, I will now turn the call over to Steve.

Steve Becker – President and Principal Executive Officer

Thanks, Lee. And good day, everyone and thank you for joining us. Before I begin my prepared remarks, I’d like to introduce Sandra Ryan-Robinson. Sandra is recently appointed as Principal Financial Officer for the Partnerships General Partner replacing Rob Jacobucci, who has been appointed to another role within TransCanada. Prior to appointment Sandra was serving as an officers of our General Partner and is also responsible for the accounting and financial reporting of TransCanada’s Canadian Pipeline segment.

If you turn to slide 4, the map on slide 4, shows our investment portfolio of six natural gas pipelines. The addition of the new assets in May 2011 has given us more diversification and more stability in terms of longer term cash flows for our unitholders. There are several shorter term items on each asset that are part of our third quarter results that we will cover in the upcoming slides. On a longer term basis, the partnership remains well positioned with strong cash flow in the future from these investments.

Turning to slide 5, as outlined in yesterday’s news release TC Pipelines reported Partnership cash flows of $43 million for the quarter. During the quarter we paid out $42 million in cash distributions to our unitholders. Net income increased in the third quarter 2011 to $41 million compared to the third quarter 2010 net income of $39 million. The third quarter 2011 net income is equivalent to $0.75 per common unit. Last week we announced $0.77 quarterly cash distribution for the third quarter. This marks the Partnership’s 50th consecutive quarterly distribution pay to our unitholders.

The third quarter distribution is in line with our second quarter 2011 distribution and represents a 3% increase over the same period last year. GTN and Bison will begin distributing cash in Q4 2011. The cash distribution from these assets will reflect both second and third quarter results. Our policy is to base our cash distribution on the prior quarter results.

In the third quarter, we made a conscious decision to keep cash at the asset level of GTN and Bison. As we will explain later, Bison has had an operating disruption and GTN was in the midst to rate case settlement negotiations. With Bison now back into full operation and the GTN rate case settlement filed we’ll commence distributions from these assets in the fourth quarter.

In terms of the specific volume flow and re-contracting statistics for the long-haul pipelines these are shown on slide six, Northern Border continues to perform well and its results reflect one of the best downstream options for shippers to move gas out of Western Canada. Average scheduled volumes for the third quarter of 2011 were approximately 2.5 Bcf a day and we're in line with levels seen from the same period last year. Northern Border continuous to experience strong demand for its transportation, it also remains substantially contracted for almost all of its capacity through October 2012.

In terms of organic growth the Princeton lateral project relating to Northern Border continues to progress well, the latter will supply natural gas to power generation facility. Construction activity started in the third quarter and we remain on schedule for an in-service date in November this year.

Moving onto Great Lakes, average schedule volumes of 2.2 Bcf a day for quarter we’re in-line with the volumes from the same period in last year. As of November 1, Great Lakes had approximately 670 million cubic feet per day of uncontracted long haul capacity. Ongoing uncertainty regarding future tolls on TransCanada’s Canadian Mainline has created uncertainty for the Great Lake shippers.

TransCanada was requested by the National Energy Board to file its 2012-2013 toll application on September 1, 2011. The toll is proposed on September 1, we’re only illustrative. TransCanada has stated that plans to file a supplemental toll application on October 31. TransCanada is also expected to file for an interim 2011 toll prior to the end of the year. That should help provide Great Lake shippers more certainty heading into next year.

Great Lakes received the major portion of its volume from TransCanada, the gas is shipped from Western Canada along the (indiscernible) section of TransCanada’s Mainline and integrate Lakes for delivery to Midwest and Eastern Canadian markets. The uncertainty around the toll for the upstream portion of this path has impacted the annual contracting pattern for Great Lakes. Our sales efforts will focus on selling this capacity on a monthly or a daily basis as well as on an annual basis.

The remaining short-term uncertainty regarding Great Lakes revenue from its unsold capacity, we are confident that its storage levels in Western Canada reach new record high levels with the winter months approaching Great Lakes will continue to attract volumes to fill this uncontracted capacity.

As seen again this quarter, Northern Border and Great Lakes continue to move significant volumes year-over-year demonstrating the strong demand for natural gas and demand for their transportation services. We expect this will continue in the future given the expected raise in gas production for the Western Canadian sedimentary basin.

I’d now like to highlight a few of the partnerships and other activities that occurred during the quarter. These are shown on slide 7. We are pleased to announce that GTN has entered into a settlement agreement with its shippers for rates effective January 1, 2012 through 2015. The settlement, which is subject to FERC approval should provide GTN with long-term revenue certainty through 2015, as it is currently contracted for 1.5 Bcf per day.

With anticipated lower volumes as a result of Riverview service, GTN is proposed to slightly increase its long haul rate to reflect a 245 million cubic feet per day of contracts that are being turned back by PG&E beginning at the end of October. Well, our settlement reflects higher rates resulting from the turn back of the last contract capacity that PG&E failed to renew. The settlement also reflects a decline in rate base since our last settlement. It also reflects a reduction in the depreciation rate, which mitigates the long-term impact of a declining rate base.

Rate case requirements are an integral part of our business and several of our pipeline assets requires to file rate cases on a periodic basis. The outcome of the rate case for GTN is a clear demonstration of the protection that regulated assets provide our unitholders.

During the third quarter, GTN experienced lower transportation volumes during the quarter versus the same period last year, primarily as a result of Riverview coming into service in late July. GTN’s average scheduled volumes were 1.8 Bcf a day, as compared to 2.3 Bcf a day in the third quarter of 2010. Flat year-over-year power demand and high water levels available for hydroelectric power generation has meant less of a demand for natural gas this year for the markets that GTN serves. We expected a decrease in volumes once Ruby Pipeline became operational. The impact to GTN’s revenues is expected to be minimal due to its long-term contracts and due to the newly settled rates that are pending for approval.

For GTN’s remaining uncontracted capacity, we believe that GTN is well-positioned due to the relative pricing advantage of Western Canadian Sedimentary Basin gas versus Rocky Mountain gas, which could bring some potential upside should there be an increased need for gas in Northern California above and beyond its current levels.

As we mentioned during our last quarterly call, Bison had a line rupture on July 20. Bison was operating at 60% of its contracted capacity for most of the quarter. The pipeline was returned to full capacity on October 8. Bison’s results reflect revenue losses of approximately $800,000 and repair costs of approximately $400,000. These amounts reflect the partnerships interest in the pipeline.

Moving on to Tuscarora, we mentioned last quarter the FERC issued an order on May 24 pursuant to Section 5 of Natural Gas Act. At this time, we continued to work through the process but we don’t have any details to provide at this time. We still expect to receive an initial decision on this proceeding by April 2012.

And then turning now to some of our general partner efforts, TransCanada continues to tie a new gas supply in Western Canadian Sedimentary Basin from the growing Northeast British Columbia shale place in the Montney and Horn River regions along with the emerging new conventional place that have a liquids component to them like the Duvernay play in Alberta.

The Horn River and ground bridge pipelines, combined with other unconventional gas developments, will bring roughly 2.9 billion cubic feet per day of contractual volume commitments into TransCanada’s Alberta System by 2014. A portion of these volumes could ultimately be available for delivery out of the province.

As TransCanada continues to bring on new gas supplies this increase in gas supply forecast is expected to have a positive impact on TC Pipelines as this gas will lead to move downstream to various demand markets. This concludes this section of my prepared remarks.

I would now like to turn the call over to Sandra, who will walk you through our third quarter financial results and further detail.

Sandra Ryan-Robinson – Principal Financial Officer

Thanks, Steve and good day, everyone. My remarks follow the presentation material starting on slide nine. Partnership cash flow decreased $2.3 million to $43.1 million in the third quarter of 2011, compared to $45.4 million in the same period of 2010. The decrease was primarily due to higher financing costs pertaining to the Partnership’s recent debt issuance and current draw on its credit facility partially offset by increased cash distributions from Great Lakes and Northern Border by $0.8 million and $0.9 million respectively.

As Steve mentioned earlier, we did not record any cash distributions for our GTN and Bison in the quarter. However, the partnership did report 10.8 million of undistributed earnings from its assets from the date of acquisition until September 30, 2011. We expect to start reporting in cash distribution in the next quarter.

The Partnership pay distributions of $42 million in the third quarter of 2011, an increase of $7.6 million or 26%, compared to the same period in 2010. This is due to an increase in the quarterly distribution of $0.02 per common unit beginning in the fourth quarter of 2010. A further $0.02 per common unit increase beginning in the third quarter of 2011 and an increase of $7.3 million from units of standards.

Turning now to slide 10, net income increased to $2.1 million to $40.7 million or $0.75 per common unit in the third quarter of 2011 compared to $38.6 million or $0.82 per common unit in the same period in 2010. This increase was primarily due to higher earnings from the 25% interest in GTN and Bison but was partially offset by lower equity income from Northern Border and higher financing charges.

Equity income from Great Lakes was $14.3 million in the third quarter of 2011, a slight decrease of $0.3 million compared to the third quarter of 2010. Equity income from Northern Border was $19.6 million in the third quarter of 2011, a decrease of $1.4 million compared to $21 million for the same period in 2010. This decrease was primarily due to low realized rates for volumes contracted on an annual basis in 2011, whereas third quarter 2010 revenues reflected higher seasonal and shorter duration contracted rates.

Costs at the Partnership level were $9.9 million in the third quarter of 2011, an increase of $3.6 million compared to $6.3 million for the third quarter of 2010. This increase was primarily due to higher financial charges resulting from higher average debt outstanding at higher average interest rates.

I’d now like to discuss our liquidity and capital resources shown on slide 11. As of September 30, 2011, there was $67 million outstanding on the $500 million revolver portion of the Partnership’s senior credit facility and $300 million outstanding under the term loan portion of the facility.

The average interest rate on the senior credit facility was 3.4% for the three months ended September 30, 2011, including the impact of interest-rate hedging activity. As we mentioned last quarter in July, the Partnership closed an amendment to its senior credit facility increasing the revolving credit facility to $500 million with LIBOR based interest rate plus a margin. The maturity date for the senior revolving credit facility was extended to July 2016.

The partnership’s remaining 300 million senior-term loan matures in December 2011. Another great example of our flexibility comes from the accordion feature on our revolver. At any time, the loan has no event of the default has occurred and is continuing under the credit facility, the partnership may request an increase in the credit facility of up to $250 million. The increased size of our revolver added with the potential for further accordion style expansion will ensure that we have sufficient coverage for our remaining term loan that comes due at the end of the year and will also allow us more financing flexibility for potential organic growth and acquisition opportunities in the future.

As we move forward, we will continue to maintain a prudent approach to cash from management directing our free cash flow to maintaining appropriate debt level, investing in ongoing operations, growing distribution to unitholders and positioning for further growth opportunities.

That concludes my prepared remarks and I will now turn the call back over to Steve.

Steve Becker – President and Principal Executive Officer

Thank you Sandra, I would like to wrap up my remarks today by leaving everyone with our key messages which are shown on slide 12. We consider our assets and essential infrastructure is the key markets they serve and drive all of their revenues primarily from fee based charges. Four of our fixed assets generate the revenues from long-term contracts further insulating us from market volatility. These are all desirable characteristic during these volatile market conditions and we are further isolated from these market conditions as a result of our minimal capital requirements.

We are supported by a strong industry sponsor in TransCanada Corporation, our general partner. They presently operate North America's largest natural gas pipeline network, something we consider as one of our key competitive advantages. TransCanada’s remaining $11 billion capital program is to be spent over the next couple of years will require additional capital to finance these projects. Within its overall financing plan TC Pipelines is well positioned to play an ongoing role if TransCanada chooses to sell an asset or additional ownerships in partially owned assets to TC Pipelines as it means to finance its capital program. The partnership has a strong balance sheet and ample amount of liquidity as being showed up with a recent financings in the capital markets over the past few quarters and it’s also further supported by our investment grade credit ratings.

In closing. I would like to emphasize that with strong fundamental supporting our entire portfolio of assets, a promising long-term outlook for gas with growth in gas supplies from our new shale plays and an increase size to our investment portfolio is backed by its strong financial positions. I am confident that the partnership is well positioned to provide stable and growing cash distributions going forward.

With that I will now turn the call back to Lee.

Lee Evans – Manager, Investor Relations

Thanks, Steve. I would now like to open the call to your questions. Operator, please go ahead.

Question-and-Answer Session

Operator

Thanks Mr. Evans. (Operator Instructions) And the first question is from Gabe Moreen from Merrill Lynch. Please go ahead.

Gabe Moreen – Merrill Lynch

Hi, good morning. Questions on GTN, I just wanted to make sure of course the PG&E capacity return back. And I think you mentioned about that being expected, but just wanted to see whether that was confirm whether that was expected or not, and then also to make sure that with the settlement doesn’t really change at all the exploration of the remaining contracts on GTN, Just that exploration contract exploration profile?

Steve Becker

Gabe, I’ll let Stuart Kampel answer that question. Stuart, go ahead.

Stuart Kampel

Okay. Thank you Gabe for the questions. Indeed the PG&E turn back of its process was expected and factored into the break case settlement provisions that we’ve under circuit earlier this year. So…

Steve Becker

And the longer term contracts…

Stuart Kampel

Long-term contracts have no impacts. The settlement has no impacts at longer term contract terminations of the contracts.

Gabe Moreen – Merrill Lynch

Thanks Stuart. And then turning to GLGT, I just had a question in terms of how the amount of one contract capacity you’re heading into the winter season with compares to last seasons under contract capacity. If you didn’t mention it before and if you did, I apologize for not casting it and then whether given the uncertainty on the mainline toll’s whether you would expect a fair amount of interruptible volumes this winter if the uncertainty are on the mainline persists?

Steve Becker

Sure Gabe. Last year Great Lakes did not have any long-hauled uncontracted capacity at this time. It generally gets sort of in the market people contract for gas supply, a contract for sales and a contract for transportation. And on Great Lakes that is hugely done on an annual basis, and that usually happens in the summer.

With the uncertainty on the Mainline tolls people have chosen to not contract this capacity and will – and so into your second question it will be sold either on a monthly basis or a daily basis. And that could be classified as interruptible I guess is, as that happens. When there becomes more clarity with the October 31, filing of the TransCanada rates for the upstream portion of the path. And more particularly with the interim rates for 2012, so that there is different opportunities for changes there that may add a lot more certainty and people amend they want the contract a little bit further forward.

In terms of the fundamentals for the actual assets, the volume that comes out of Alberta on a sort of a monthly basis is very dependent on storage levels and weather. On a kind of a macro basis compared to last year with the Bison Pipeline starting and the Ruby Pipeline starting, basically its displaced approximately 800 million a day of gas into Alberta that now has to flow down to different path. And since the Western Canadian supply and demand were roughly balanced, there is that amount that we would expect to flow East towards on the Canadian Mainline.

So the bottom line at the end of this is that, this we see as a shorter term issue that is impacting the annual contracting process. It will be into a monthly and daily process until we can get a little more certainty. We think once that certainty is there then people will go back to their normal contracting patterns. I think consequently we may have a little bit of uncertainty about our revenue on Great Lakes in the fourth quarter of this year.

Gabe Moreen – Merrill Lynch

Thank you. I appreciate it.

Operator

Thank you. (Operator Instructions) And the next question is from Michael Cerasoli from Goldman Sachs. Please go ahead.

Michael Cerasoli – Goldman Sachs

Thanks. Good afternoon. Just a quick question on – more of a high level question on Northern border and North Baja, can you maybe spend some time on just how a cross boarder flows are changing and maybe perhaps if there’s – what your opportunities there maybe, if any?

Steve Becker

If I could just clarify you said Northern border or North Baja or…

Michael Cerasoli – Goldman Sachs

No, North Baja, in terms of kind of flows from Mexico etcetera?

Steve Becker

Well, I think North Baja is an interesting pipeline and that it connects to the El Paso System in Arizona and flows into the Gasoducto the Bajanorte in Baja Mexico. And it has contracts to flow gas from the United States into Mexico to serve power plants in the North Baja region of Mexico. There’s an LNG facility at Costa Azul South of Tijuana and the shippers on that LNG facility have contracts that if LNG were to come in at Costa Azul they would ship on Gasoducto to Bajanorte in Mexico and on North Baja to get gas into the Southern California market. So currently the flows have generally been from the United States into Mexico port North to South. There has been instances of flows from South to North when the terminal was first being tested. So that’s the situation. All of those contracts are in place well into past 2020 I believe Stuart it’s -- sorry, can you just repeat that?

Michael Cerasoli – Goldman Sachs

The contract is going to the late 2020s?

Steve Becker

And they really don’t have any reopeners or anything else. So that we view that as a very solid asset with contractual underpinning that asset has.

Michael Cerasoli – Goldman Sachs

Okay. And then actually switching over to the Great Lakes, I just have a quick question on, you know in your near term volume issues, did you get a sense on -- do you get the sense of some of these volumes are going elsewhere or maybe other pipelines like Northern Border, GTN or do you get a sense that natural gas just staying in Western Canada?

Steve Becker

During the month of October, it was probably staying in October and they are very large storage injections in Alberta, and the storage levels in Alberta are getting to all time high. So as you go into November and December as the weather changes, we expect that we will see flow is going down street and so that will be more contacted on a monthly basis as people contract for the months of November that’s currently activity going on as we speak. And the full amount isn’t fully contacted that way it will be start to be sold on a daily basis. So that's the gas, Northern Borders essentially fall in GTN’s contract those are fairly consistent over the quarter being down about 450 million a day because of Ruby on a year-over-year. But, if I could just sort of re-summarize what I’m saying with all these different facts is that there is a gas in Alberta, it’s currently going into storage, so winter approaches it’s likely to go east and that's where Great Lakes will probably get its historical market share.

Michael Cerasoli – Goldman Sachs

Okay. And then I just have one final general housekeeping question on. I just – I’m a little confused as to why there were no cash distributions in the third quarter each of the deal, the Bison and GTN, of course am I missing something. There is – I think you said the first cash distributions will be received in the fourth quarter. I’m just trying to understand that gap?

Steve Becker

Basically, the Bison one is – we would have distributed the cash in the third quarter for May and June. Because we had the disruption in Bison, we chose just to leave the cash in that operating entity while the disruption was ongoing. GTN, we’ve been doing a variety of things in – relative to the rate case and we basically didn’t make that distribution. So we will be making it in the fourth quarter. So there is nothing really – it’s more an administrative item. There is nothing wrong with the assets or anything else. So I think you’ll see that we will in the fourth quarter, make the distribution for both the May, June period and for the third quarter. There is generally a one quarter lag in our distributions relative to the cash flow.

Michael Cerasoli – Goldman Sachs

That makes perfect sense. Thank you for taking my questions.

Steve Becker

Thanks, Michael.

Operator

Thank you. (Operator Instructions) And the next question is from Ryan (indiscernible). Please go ahead.

Unidentified Analyst

Hi. Can you refresh me on the – the contract termination profile for GTN? What does that look like?

Steve Becker

So we currently have contracts on GTN of about 1.5 billion cubic feet per day. Those contracts extend out for over a longer period of time first coming off – some coming off in 2015 and that was extending out to 2033. I believe it is the latest one. Primarily, the contracts go up to 2021 related to the 30-year contracts that were underpinned with the 1991 expansion out of the PG&Es or GTN system.

Unidentified Analyst

Okay.

Steve Becker

The rate case settlement, I think it's important to understand that the rate case settlement was actually – the rates under the settlement were largely supported by the contracted capacity of the GTN pipeline and not the physical or historical flows of the pipeline. So what we’ll see going forward is the contracts based or revenues based on the contract of capacity of the pipeline.

Unidentified Analyst

Okay. And I mean do you see further – as you raise the rates and you’ve got competition from Ruby, I mean do you see risk of further volume or further capacity being turned back down the road?

Steve Becker

Well, on a going forward basis we think we’ve to look at the relative competitiveness of GTN and the Ruby pipeline and the options that are available both to the Rocky Mountain gas producers and the Western Canadian gas producers. With the rates that are coming into effect and our long-term view of how GTN will compete with other options, we see GTN as a strongly competitive pipeline into that market. The Ruby Pipeline is a fairly high cost pipeline that came into service here earlier this year. And we don't really see a lot of additional capacity being send up on that pipeline in the near term, but we do see GTN as a relatively solid player relative to the competition from Ruby. And as Steve indicated as the Western Canadian basin gas continues to grow. We see GTN as a good outlet for gas for GTN or on the GTN system into California. So we see that as a strong indicators of performance for GTN going forward.

Unidentified Analyst

Okay. And I mean you’ve talked about the additional gas coming out of BC, there've been bunch of projections about the amount of gas that’s going to be consuming in the tar sands as they pursue extracting the oil up there, what kind of growth and demand for gas out of the tar sands, is your forecasts encompass?

Steve Becker

Maybe I'll answer that – if we don’t mind we’d also like to refer to as oil sands as opposed to the tar sands. And so in the sort of growth in Alberta there is a lot of different activity in connection with that and so that the growth is about a Bcf a day over a ten-year period, so as you actually grow the Alberta demand was 4 on an annual basis – 4 Bcf a day 10 years ago, but five now and projected to six 10 years from now and so that the Canadian supply would have to grow at above that same rate to have an extra Bcf a day over the next 10 years to match that demand. So, in our current forecast, we see that happening or even exceeding that and the net result is the amount to go down the downstream pipelines is basically flat or slightly increasing over this next 10 year timeframe.

Unidentified Analyst

Okay. So, you guys are more pessimistic I guess than people like (indiscernible) who – I think they've got a three Bcf increase over the next decade or so going up to the oil sands?

Steve Becker

Well we think where you may see some of the differences is there, probably, perhaps more optimistic than on the oil sands which for where the optimism can have is there is a second factor that they may have in their study and I don't have the study in front of me, so I can't confirm that, but if I could generalize onto differences in forecasts. Some of the Oil Sands is actually upgraded in Alberta and requires a lot more energy use, and that’s where some of the gas is being utilized.

If you assume less upgrading in Alberta and more of that oil shipped to areas in the Houston area that already have that upgrading capability that isn’t being utilized because of declines in Venezuelan and Mexican oil. That creates a difference in the gas forecast. So that one assumption can drive fairly different numbers. We believe that we’re tracking on this trend and we analyze this on a fairly regular basis. And TransCanada itself is the major supplier to the Oil Sands and has all that capability built into its areas. So we can always beat the forecast, and I think that’s what creates market views. But as a generalization, I think there, we don’t see that the growth in the Oil Sands vastly outstripping the current growth in the Canadian gas. We see them being very parallel.

Unidentified Analyst

Okay. Thanks for the color.

Operator

Thank you. Your next question is from John Tysseland from Citigroup. Please go ahead.

John Tysseland – Citigroup

Hi, good afternoon.

Steve Becker

Hi John.

John Tysseland – Citigroup

I just had a quick follow-up question about distributions coming out of Bison and GTN for the quarter. Can you remind us what the capital structure is at those investments and the liquidity available to each one of those operating entities?

Steve Becker

The Bison structuring has no debt, its 100% equity. So there is no debt in the Bison entity. So the cash flow can be distributed from that particular entity. In GTN, there is an amount of debt at that entity that it has to service. The LP has 25% of it and its proportionate share is about 81 million. So on an aggregate basis it would be $325 million in that particular entity. So I think that the – as I stated earlier, we didn’t distribute in this quarter out of those assets, it didn’t have anything to do with the capital structure. It was just choice of – it was just a choice of a process, if did we leave cash in those entities and sweep the cash out of it at what particular time. And so we plan to make that sort of like the end of the fourth quarter or year-to-date numbers will look very normal. And so it’s just an administrative timing item.

John Tysseland – Citigroup

What is the liquidity for each one of those entities, I mean is there – do they each have credit facilities or availability of capital?

Steve Becker

No, generally in both cases they are owned 75% by TransCanada and 25% by Partnership. And so the Partnership could get a cash call from the entity and the Partnership would fund it out of the general credit facility that we referred to on slide 11, where we are about $67 million drawn on a $500 million credit facility. For the TransCanada portion, for the remaining 25%, they would have to draw on general TransCanada funds and TransCanada being a $50 billion dollar company because in aggregate asset value has enough liquidity to fund those operations quite regularly. Currently, they’re more generally cash generators then cash requires because there is no construction going on, there is a minor amount of construction being finished on mines. So generally they’re cash generators not cash drawers. So there isn’t really a funding need at this time. There may be in the future if we further develop assets almost on those pipelines.

John Tysseland – Citigroup

Great, thanks for the clarification. Thank you.

Operator

Thank you. The next question is from David LaBonte from Kayne. Please go ahead.

David LaBonte – Kayne

Hey Steve, how are you?

Steve Becker

Fine, Dave.

David LaBonte – Kayne

Just a follow up on the 3Q distribution for Bison and GTN that were held back, did the volume disruption on Bison or the rate case on GTN reduce, what will ultimately be distributed to TCLP?

Steve Becker

On Bison, it did reduce it and so the pipeline operated at about 60% of capacity for little over two months. And so there is on the LP share there was $820,000 less of revenue that would have impacted the distribution. In terms of costs, there was - the partnership share was about $400,000. So the combined amount was about $1.2 million for the partnership. On GTN, there is really no cash disruption. It was probably a more just an administrative item in terms of focusing on the rate case and not focusing on making a distribution on the new asset. So I think people keep asking this question. There's no real problem there. It’s just an administrative item that we plan to correct in the next coming upcoming quarter.

David LaBonte – Kayne

Okay, and second I guess with respect to Great Lakes, it seems that shippers are probably are most interested in the interim poll for 2012 and I know we have our TRP have the filing on October 31. Do you have an estimate for when TransCanada will release the interim poll for 2012?

Steve Becker

No, we don't at this time. And I think there is work underway and I think they’ll be -- perhaps sometime in mid November sort of an ability to get the one piece in and then they’ll have to file the next material. So whether it’s done – we normally effected in November as opposed to December I guess is what the issue would be. And that would then maybe clarify some information for people contracting for the month of December. And that’s a little bit what the unknown is. So because the shippers don’t have that, it’s easier to wait for a month and see what all this information is that’s about to be filed.

David LaBonte – Kayne

And do you think it’s probably fair to assume that the normal contracting patterns that Great Lakes typically has, you’re probably not going to see that until the early summer 2012 and that really from – from now until then, a reasonable guess would be daily to monthly contracts?

Steve Becker

That’s probably a reasonable guess over the winter. Great Lakes is usually very well – is a very desirable pipeline in summer months to refill the storage in the Michigan and Eastern Ontario areas. And so, where that can slight differ is, if we have a very large group trying to sign up from April till October, everyone bids the maximum rate. In order to get the capacity, somebody has to extend the term, and you may extend it backwards to include March and February to capture that space. So, the bottom line is, we probably have daily, monthly over the winter but we likely will sell somewhere in block in a seven-month block.

David LaBonte – Kayne

And just last question and I think you’ve more or less answered this, but with respect to GTN, the capacity that PCG turned back, you really don’t anticipate seeing any additional capacity outside of what’s already happened to date. Is that a reasonable assumption or have you modeled that there could be additional loss of volumes on GTN as a result to Ruby?

Steve Becker

Sorry. I was thinking on Great Lakes, so in your question, were you asking on Great Lakes or on GTN?

David LaBonte – Kayne

No, GTN, changed pipelines.

Steve Becker

Okay.

Stuart Kampel

Yeah, so.

Steve Becker

Maybe Stuart can help you out on that one?

Stuart Kampel

So I feel that. So no we don’t expect any of the contract changes over the near term. So as I said the contracts are long-term contracts, in terms of volumes based on the rates settlement it doesn’t really matter what the volumes will be, we’ll have the contracts to support the revenue.

David LaBonte – Kayne

Right.

Stuart Kampel

As we go forward depending on the supply availability in the WCSB and the demand in California relative to Ruby, there might actually upside to the volumes on GTN as we kind of work through the markets characteristics and the weather patterns over the next few months. So I don’t see much downside on the flow side affecting revenues for the asset.

Steve Becker

And perhaps if I could just add, in looking at our portfolio, if there was more lower flows on Ruby for whatever reason and flows increased on GTN, we would make incremental money on GTN and that might take away from flows where we might have made money on Great Lakes. So in certain ways our portfolio has a bit of a self hedging in it. If there isn’t any flows down GTN, well that means there is more to go on Great Lakes. So we kind of – we’re positioned to handle the flows whichever direction they go.

David LaBonte – Kayne

Okay, guys. Thanks.

Steve Becker

Thanks David.

Operator

Thank you. The next question is from Gabe Moreen from Merrill Lynch. Please go ahead.

Gabe Moreen – Merrill Lynch

My follow-up got asked, so thank you.

Steve Becker

You’re good Gabe?

Gabe Moreen – Merrill Lynch

I am good. Thank you.

Steve Becker

Okay, great.

Operator

Thank you. There are no further questions registered at this time, Mr. Evans.

Lee Evans – Manager, Investor Relations

Okay, thank you. Thanks everyone for your participation here today. We appreciate your interest in TC Pipelines, LP and look forward to talking to you soon. Bye for now.

Operator

Thank you. The conference has now ended. Please disconnect your lines at this time. And thank you for your participation.

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Source: TC PipeLines, LP's CEO Discusses Q3 2011 Results - Earnings Call Transcript
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