TC PipeLines' CEO Discusses Q4 2011 Results - Earnings Call Transcript

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TC PipeLines, LP (NYSE:TCP) Q4 2011 Earnings Call February 17, 2012 12:00 PM ET


Steven D. Becker – President and Director

Sandra Ryan-Robinson – Principal Financial Officer

Stuart Kampel – Vice President and General Manager

Lee Evans – Manager, Investor Relations


Avi Feinberg – Morningstar

Rob Chisholm – Center Coast Capital

Ted Durbin – Goldman Sachs

William Adams – FAMCO


Good day, ladies and gentlemen. Welcome to the TC Pipelines LP 2011 fourth quarter results conference call. I would now like to turn the meeting over to Mr. Lee Evans, Manager, Investor Relations. Please go ahead.

Lee Evans

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

Please note that a slide presentation will accompany the remarks and is available on our website at 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 accomplishments in 2011 followed by a review of our fourth quarter results and an update on the various developments concerning the Partnership and its sponsor, TransCanada Corporation.

Sandra will then review in detail our financial results for the fourth quarter. Steve will then return to wrap up the Partnership’s prepared remarks with some key takeaways. Following the prepared remarks, I will ask the 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’d now like to turn the call over to Steve.

Steve Becker

Thanks, Lee, and good day, everyone and thank you for joining us. Before I discuss our results for the quarter, I’d like to take a few minutes to quickly review some of our accomplishments in 2011 and highlight a very successful year for the Partnership. All of these activities, I’m proud to say, have created some very solid foundations which position us well as we pursue further growth opportunities.

In 2011, we increased our cash distributions paid by 3.4% compared to 2010. This was the twelfth year of increasing our cash distributions and this is strong evidence that our low risk business strategy continues to deliver value to our unit holders. The partnership also saw a strong financial performance across all of our assets. In 2011, Partnership cash flows increased 12% excluding the $20 million one-time cash distribution from GTN leaving us with a 1.3 times cash distribution coverage for the year. We generated over $200 million of cash flows for the first time in our history and now have assets in excess of $2 billion. Net income for the year was $157 million, or $3.02 per common unit.

Of course, these results would not have been possible without the acquisition of interests in GTN and Bison back in May from our sponsor, TransCanada. This acquisition enabled the Partnership to add significant long-term contracts to its overall portfolio while also diversifying the markets that it serves with the addition of Pacific Northwest in northern California via GTN.

Powder River Gas, which is accessed via the Bison pipeline, also diversifies our connections to various supply basins. In May we raised $338 million in equity in connection with GTN and Bison. In June we raised $350 million in ten-year debt through our first public debt offering. Bearing an interest rate of 4.65% made our debt one of the cheapest raised by an MLP last summer in the ten year market space.

This debt offering was supported by investment-grade credit ratings of BBB from S&P and Baa2 from Moody’s. In July we extended and doubled our revolving credit facility to $500 million from $250 million providing increased financial flexibility in pursuit of future growth.

I’ve planned to discuss the GTN and Tuscarora settlements in more detail later in the call. I wanted to quickly highlight that we were able to reach negotiated rate case settlements for both pipelines in the second half of 2011. We believe that negotiated outcomes are beneficial for our unit holders. Outcome from these settlements will provide long-term cash flow certainty for the Partnership.

Finally, this past December, the Partnership moved over to the New York Stock Exchange and changed its trading symbol to TCP. We believe this move better aligns us with our MLP peers, and our sponsor, TransCanada, will also provide better trading liquidity for our unit holders. In all, a busy year for our partnership, but one that we believe has created solid foundations for future growth.

Turning to slide 5 in our package, fourth quarter 2011 financial highlights, I’m turning now to our quarterly financial results. TC PipeLines reported strong partnership cash flows of $83 million for the quarter. With distribution policies now in place for GTN and Bison, the Partnership recorded a $20 million one-time distribution from GTN.

At the time of our acquisition, GTN had a cash balance. This cash was accounted for in closing adjustments for the acquisition back in May. We also recorded GTN’s second and third quarter cash distributions of $4.9 million and $7.7 million respectively.

For Bison we recorded second and third quarter cash distributions of $2.7 million and $2.9 million respectively. Second quarter cash distributions reflect approximately two-thirds of a quarter given the acquisition timing in early May. During the quarter we paid out $42 million in cash distributions to our unit holders. Net income increased in the fourth quarter 2011 to $38 million compared to fourth quarter 2010 net income of $37 million. The fourth quarter 2011 net income is equivalent to $0.70 per common unit.

On January 17th we announced a $0.77 quarterly cash distribution for the fourth quarter. The fourth quarter distribution is in align with our third quarter 2011 distribution and represents a 2.7% increase over the same period last year. The distribution also marks the Partnership’s 51st consecutive quarterly distribution paid to our unit holders.

I’d now like to highlight a few of the Partnership’s other activities that occurred during the quarter, which are shown on slide 6. Last quarter we announced that GTN has entered into a settlement agreement with its shippers for rates effective January 1st, 2012 through 2015. As expected, the settlement was approved by the FERC in the fourth quarter and is now providing long-term revenue certainty through 2015 as GTN is currently contracted for approximately 1.5 Bcf a day.

As a recap, our settlement reflects higher tariff rates resulting from the turn back of loss contracted capacity that PG&E failed to renew at the end of October 2011. The settlement also reflects the decline in rate base since the last settlement and a reduction in the comp set depreciation rate. The lower depreciation rate helps mitigate the long-term impact of a declining rate base over time.

For GTN’s remaining un-contracted capacity, we believe that GTN is well positioned due to the relative pricing advantage of western Canadian sedimentary gas versus Rocky Mountain gas, which could bring some potential upside should there be an increased need for gas in the Pacific Northwest or northern California above and beyond GTN’s current contracted volumes.

Moving on to Tuscarora, as I mentioned earlier, we are pleased to report that Tuscarora reached a negotiated settlement with its largest shipper in late December pertaining to the section 5 rate case. The negotiated settlement, which is pending FERC approval, is expected to lower transportation revenues by approximately $6 million on an annual basis as a result of a lower tariff rate.

The tariff rate reduction is offset by a lower composite depreciation rate, which results in a decrease to net income of $3 million per year. As part of the settlement, Tuscarora was able to extend its contracts with its largest shipper for three years, which now means that Tuscarora is fully contracted through until the end of 2019.

Periodic rate cases are a recurring part of the regulated natural gas pipeline business and many of our pipelines are required to file rate cases on a periodic basis. The outcome for the rate cases for GTN and Tuscarora effectively create increased cash flow certainty and add future stability to the Partnership’s existing foundation of long term contracted assets.

Turning now to the re-contracting statuses for Northern Border and Great Lakes on slide 7, Northern Border continues to experience strong demand for its transportation services despite the low gas price environment and overall weak basis spreads across North America. Northern Border is now contracted for substantially all of its capacity through March 2013. Due to its relative competitive strengths, including gas basin on basin competition for its capacity, we anticipate re-contracting of Border’s capacity to continue.

In terms of organic growth, Northern Border’s Princeton lateral project was brought into service during the fourth quarter as expected. This nine mile lateral now supplies natural gas to a prior generation facility under a ten-year contract. Great Lakes volumes in the fourth quarter reflected un-contracted capacity since November 1st, 2011. The unusually warm winter and lack of demand for natural gas in Great Lakes’ markets meant that it was unable to contract its un-contracted capacity on a short-term basis.

While Great Lakes is traditionally being fully contracted, it currently has approximately 75% of its long haul capacity contracted through to October 2012. Great Lakes’ ability to sell its current and future available capacity will depend on the future market conditions where a number of factors will impact the re-contracting. These factors include the weather for the remainder of the winter and into the summer months, levels of natural gas storage, the price of natural gas liquids, and the associated impact of natural gas production in North America, and the outcome of TransCanada’s mainline toll hearing.

Turning quickly now to highlight some of the general partners’ efforts, TransCanada continues to tie in new gas supply in western Canada’s sedimentary basin from the growing northeast British Columbia shale plays in the Montney and Horn River regions.

The Horn River and Groundbirch pipelines, combined with other unconventional gas developments, are now expected to bring roughly 3.4 billion cubic feet per day of contractual volume commitments into TransCanada’s Alberta system by 2014, an increase of 500 million cubic feet per day from the last quarter. A portion of these volumes could ultimately be available for delivery on our pipelines. As TransCanada continues to bring new gas supplies online, we see our pipeline assets being well positioned to move this gas downstream to various demand markets.

This concludes this section of my prepared remarks and I would now like to turn the call over to Sandra, who will discuss our fourth quarter financial results in further detail.

Sandra Ryan-Robinson

Thank you, Steve. My remarks follow the presentation material starting on slide 9. Partnership cash flows increased $31.6 million to $83.3 million in the fourth quarter of 2011, compared to $51.7 million in the same period of 2010. This increase was primarily due to a $20 million one-time cash distribution from GTN relating to its cash balance at the time of the acquisition, as well as second and third quarter distributions from GTN and Bison.

Offsetting these higher cash flows were slightly lower cash distributions of $1.7 million and $2.3 million from Great Lakes and Northern Border, respectfully, as well as higher financing costs from higher average debt outstanding. The Partnership paid cash distributions of $42 million in the fourth quarter of 2011, an increase of $6.6 million compared to the same period in 2010, due to an increase in the number of units outstanding and an increase in the quarterly distribution of $0.02 per common unit paid relative to the fourth quarter of 2010.

We have received fourth quarter cash distributions from our four equity investments in the amounts of $10.8 million, $25 million, $5.4 million, and $3.9 million for the Great Lakes, Northern Border, GTN and Bison respectively. These distributions totaling over $45 million will be reflected in our first quarter 2012 financial statements. Our financial performance in the fourth quarter and throughout 2011 is a reflection of our strong portfolio assets.

Moving now to slide 10, net income increased marginally by $1.2 million to $38.3 million, or $0.70 per common unit in the fourth quarter of 2011 compared to $37.1 million, or $0.79 per common unit in the same period in 2010. This increase was primarily due to higher earnings from the 25% interests in GTN and Bison and other pipes, but was partially offset by lower equity income from Great Lakes and higher financing charges.

Equity income from Great Lakes was $10.2 million in the fourth quarter of 2011, down $4.5 million compared to the fourth quarter of 2010. This decrease was due to lower transmission revenues resulting from un-contracted long haul capacity and unseasonal weather, which impacted our ability to sell this capacity on a short-term basis.

Net income from other pipes was $10.2 million, an increase of $0.9 million compared to the fourth quarter of 2010. This increase was primarily related to higher revenues earned from North Baja due to the additional supply brought on from the unilateral earlier this year.

Costs at the Partnership level were $8.9 million in the fourth quarter of 2011, an increase of $2.5 million compared the $6.4 million for the fourth quarter of 2010. This increase was primarily due to higher financial charges resulting from higher average debt outstanding at higher average interest rate.

Turning now to our liquidity and capital resources, in December, the Partnership’s $300 million senior loan was repaid. The loan repayment was made by drawing on the Partnership’s $500 million senior revolving credit facility. As of December 31, 2011, there was $363 million drawn on the revolver. The average interest rate on the senior credit facility was 3.5% for the three months ended December 31st, 2011, including the impact of interest rate hedging activity. Since the end of the year, we used the one-time distribution from GTN along with some additional cash to pay down our line of credit in January and now have $332 million drawn on the credit revolver as of February 16, 2012.

Moving into 2012, the partnership no longer has any hedges in place on its variable interest rate debt. The amount drawn on our credit facility is subject to changes in LIBOR rates. We continuously monitor the debt capital markets and look to term out all or a portion of our floating rate debt when we deem it appropriate and prudent. The increased size of our revolver ensures that we have sufficient liquidity, should it be required.

We also have at our disposal liens of the accordion feature on our credit revolver, which would allow us to access another $250 million, ensuring that we have financial flexibility for pursuing growth opportunities. Our conservative capital structure and investment grade credit ratings will allow us to take on additional leverage as we look to grow our asset base. With minimal equity needs, we believe this could significantly benefit our unit holders.

As always, we will continue to maintain a prudent approach to cash flow management directing our free cash flow to maintaining appropriate debt levels, investing in ongoing operations, growing distributions to unit holders, and we believe that our financing utilities in 2011 have positioned us well for future growth opportunities.

That concludes my comments on the fourth quarter 2011 financial results. I’ll turn the call back to Steve.

Steve Becker

Thanks, Sandra. I’d like to wrap up my remarks by leaving everyone with some key takeaways for the quarter shown on slide 12. The partnership had a very successful year in 2011. Cash flows increased 12% to over $200 million excluding the one-time cash distribution from GTN. Net income also increased on a per-unit basis to $3.02, a 4% increase compared to 2010.

Our new assets, GTN and Bison, are now contributing to ongoing partnership cash flows and their long-term contracts bring increased diversification, stability and predictability to the Partnership’s overall portfolio of assets as we move forward into 2012. The Partnership has a strong balance sheet and ample amount of liquidity that is being shored up with our financings in the capital market over the course of 2011 and is further supported by our investment-grade credit rating.

We are supported by a strong industry sponsor in TransCanada Corporation, our general partner. Although TransCanada has indicated they no longer require subordinated capital to fund its remaining capital program, as a result of the Keystone XL project delay, the possibilities of future dropdowns still remain an option open to them as they look at new acquisitions and capital projects where the LP becomes a means to finance this incremental growth.

In the meantime, the partnership is not standing still. We continue to look to grow through third-party acquisitions and for opportunities to expand our existing pipeline systems and believe our low general partner cash take puts us in a position to be competitive when looking at third-party acquisitions. As always, we remain focused on investing in high-quality North American energy infrastructure assets that are underpinned by strong business fundamentals that provide stable cash flows.

In closing, I would like to emphasize that with an increased size to our investment portfolio that is all backed by a sound financial position, I’m confident the Partnership is well positioned to provide stable and growing cash distributions going forward.

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

Lee Evans

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

Question-and-Answer Session


Thank you. We will now take questions from the telephone lines. (Operator instructions) We do have a question from Ted Durbin from Goldman Sachs. Please go ahead.

Ted Durbin – Goldman Sachs

Thanks. Can you just talk a little bit about what your organic growth opportunities are? I mean, what are you thinking about your growth capital spending for 2012? I realize you just brought on the Princeton lateral, but what other kind of growth capex might you be putting in place?

Steve Becker

I think that the amounts in 2012 are actually fairly small and our reference is more to growth opportunities over the longer term. There’s different opportunities that come from growth in power opportunities off the pipeline and we have several of those underway.

On something like Northern Border, there’s interconnects with growing Bakken supply that have small amounts of investment, so within that, there’s not major capital required in 2012, but there is opportunities that would result, if you look forward over a five- to ten-year period.

Ted Durbin – Goldman Sachs

Okay. I’m curious about the power generation. The timing of that is related to when you think, say, co-plants retire or is it -- just kind of give us a little sense of the trajectory here of how that gas domain comes on.

Steve Becker

Well, I think it’s -- generally, the power markets are fairly regional, so there’s the opportunities where power plants retire. There’s other opportunities where -- such as the coal plants, where -- There’s also other opportunities where someone could put in a new lower heat rate unit and replace a much higher heat rate unit and that creates opportunities where those do exist in individual pockets.

It’s hard to generalize because it’s such a specific regional market and there are growing power demands in certain regions along the -- throughout the different pipeline network. I’m in a very generalized area, but the actual opportunities are very site- and individually specific.

Ted Durbin – Goldman Sachs

Got it, and then just last one for me is what sort of -- the puts and takes we should think about for growth in the distribution for -- I think you went through it before, but what would you say that one or two biggest things that we should think about are, or think about raising the distribution for 2012?

Steve Becker

Well, I think that when you look at the history that the Partnership has had, is it’s grown its distribution from $1.80 at the start up to its current level, and we’ve done that on a sort of a very steady measured pace, and so what we’ve been able to do is, over that time, is add assets into the Partnership through either buying third-party assets, buying venture positions from other partners, or buying assets from third parties at the TransCanada level where the LP is part of that partnership, or buying assets as we did with GTN and Bison from the partnership that gave TransCanada financing capability for different other assets.

So, there’s about three or four ways that the acquisitions come about and they tend to be very opportunistic, and so as we do those, we’ve had a track record of being able to do that and we then make an increase in distribution that is a little bit more steady pace. They’re not exactly tied to the actual acquisition.

So, in any case, the distributions are sort of measured at the board level of what is that, plus how is the whole portfolio performing of all the existing assets? And what we’re finding right now is we now have six pipelines in the portfolio and it’s a much broader portfolio and five of the six are fairly contracted and Great Lakes is the one that has some short-term uncertainty, but we believe is structured very well in the long term.

So, those are the types of underlying partnership factors, plus the possibility of future acquisitions, and the combination of that is what goes into the -- looking at the distribution opportunity, the growth and distribution opportunity in the long run.

Ted Durbin – Goldman Sachs

Great. I appreciate it. Thanks. Those were my questions.

Steve Becker

Thanks, Ted.


Thank you. (Operator instructions) The next question is from Avi Feinberg with Morningstar. Please go ahead.

Avi Feinberg – Morningstar

Hi Good morning.

Steve Becker

Good morning, Avi.

Avi Feinberg – Morningstar

Just a question on Great Lakes. Do you think that that 1.8 Bcf per day figure is a kind of a reasonable assumption for the rest of the year given the current contract status?

Steve Becker

Well, I think that that’s a -- When we look at that, it’s a -- The Great Lakes area has a number of assumptions involved in it when you’re actually trying to respond to that, and so there’s some near-term uncertainty with regards to Great Lakes revenue and throughput, and so some of the factors that would go into trying to answer that are the weather, both winter and summer, demand for gas, so it’s been unusually warm through this last winter, and that’s, as you might know, and it’s what’s the summer weather and a return to normal weather, if there is such a thing as normal.

The second one is how does gas production across North America respond to current natural gas pricing environment, and the third is what’s the status and resolution of the TransCanada mainline rate case that would have a hearing through the summer and get a result sometime that might be expected possibly in the first quarter of 2013.

So, while you look at that in trying to answer what’s the short-term answer, there’s a lot of very different short-term factors, but when we look at it going out a little bit further, as Great Lakes is a pretty critical part of the natural gas infrastructure, it usually has very good connections for flowing gas in the summer to storage in Michigan. That’s its primary strength, and then it has access to a lot of winter heating markets across the upper Midwest states that are there, so they have a lot of short-term uncertainty, but a long-term good position, and that’s where it’s difficult to see what people will do through the summer for the contracts starting on November 1st.

Avi Feinberg – Morningstar

Okay, so with storage, I assume it’s pretty full and off of A&R right now if that would be a near-term bearish case for more volumes coming along, Great Lakes. Is that the right way to think about it?

Steve Becker

It is, but storage is also very full in Alberta, and so, to a certain extent, through the summer, depending both on the weather and the competitive other prices and how the supply reacts, if the storage is more full in Alberta, then people may be incented to go down to Great Lakes to fill the storage there.

It is not as -- on a percentage basis, it’s a lower percentage of being full right now compared to the Alberta storage. So, there -- What’s difficult in trying to answer is there’s about five or six factors all going on at the same time and it’s difficult to isolate it just to one.

Avi Feinberg – Morningstar

Sure. Okay, well, thanks for some detail on that. And then, maybe just one other question to follow up on Ted’s question about some of the coal to gas switching opportunities. I’m just wondering if you could talk about potential size of any of those projects or how close the utility might have to be to Northern Border for that to make sense, and what amount of gas would be acquired for the project to be economic, or just any details along those lines?

Steve Becker

Well, whether it’s Northern Border or even GTN, there’s one opportunity that’s back in sort of the planning stages and generally, the laterals could be -- The siting of a newer plant would be dependent on the transmission grid and the proximity to the gas pipeline.

So, in the example of Princeton, there’s a nine-mile lateral and they signed up a ten-year contract, and generally, a $500 million -- A plant normally, with a normal size plant that would be -- would end up in about 80 million cubic feet a day of gas that you would end up getting signed up, so there’s an example where we’re working on a project like that off of GTN.

There’s other opportunities that happen, and so they can come from coal requirements. They can come from just increased demand in that particular locale and they can come from someone saying that with the lower gas prices that we’re currently experiencing, if you thought that was a longer term expectation, it may be competitive. And, what the net result would be, if even though we may not quite have quite as much capital, we would just see a much higher utilization of gas on our system, and currently we’re seeing a much higher utilization of gas versus coal this year.

So you may get higher utilization, but with existing facilities. So there’s sort of the combination of two or three different opportunities regionally, small amounts of capital, but $80 million a day to $100 million a day on a long-term contract, and thirdly, just higher utilization because people run more gas relative to coal.

So that’s sort of the nature of the activities and they all kind of come about and over a five- to ten-year period.

Avi Feinberg – Morningstar

Alright, great. Thanks for walking through that, Steve. I appreciate it.

Steve Becker

Thank you.

Lee Evans

Thanks, Avi.


Thank you. The next question is from Rob Chisholm with Center Coast Capital. Please go ahead.

Rob Chisholm – Center Coast Capital

Good morning. Congratulations on a good year diversifying the portfolio of assets as well as obtaining the investment grade credit ratings.

My question is in regards to the cash distributions from Bison as well as GTN. I know with GTN you withheld the distribution in the third quarter because of some of the rate settlement issues at GTN, and then you withheld a distribution of Bison because of the disruptions that you had to shut down the pipeline with, and then you had the one-time $20 million distribution from GTN.

So, in terms of cash distributions from those investments, it was a little bit choppy. How should we think about it moving into 2012? Should it be more on the one quarter delay on the distribution from the equity earnings?

Steve Becker

Yes, and maybe I could just -- I think you could look at that and I think when Sandra was making her remarks, if I could just repeat a couple of those numbers, and I’m just going to change a page to get to it, is that on February 1st, for the fourth quarter, we received $25 million from Northern Border, $10.8 million from Great Lakes, $5.4 million from GTN and $3.9 million from Bison, so that Bison was, with ten-year contracts, that probably is a fairly consistent number.

GTN had a slightly lower quarter because the PG&E contract left at the end of October and the rate case settlement didn’t start until the first of January, so there’s that aspect there. Great Lakes had one month of the quarter being fully sold out and then some of the lower contracting levels for two of those months.

So, those particular numbers, I think that’s about as far as we can go in terms of trying to give you some idea of what the levels would be, and, obviously, as we go forward, there’s still a variety of other factors that all factor in, so that’s what we have received on February 1st with this one quarter delay and how we distribute our cash distributions. That’s the amounts we received from the different assets.

Rob Chisholm – Center Coast Capital

Steve, could you elaborate a little bit on the $20 million one-time payment?

Steve Becker

Yes. What happened with the $20 million was when we were actually closing the transaction, that was part of the working capital adjustments, and so the cash was being held at the entity when we acquired the asset, and so when we acquired it, we bought the asset for -- the two assets together for $605 million plus closing adjustments.

So part of the closing involved putting cash in relative to our share of cash that was at that entity, and so the timing for this cash distribution coincided with the implementation of the cash distribution policies that happened since our last call, and they’re now in place for GTN and Bison.

Rob Chisholm – Center Coast Capital

Okay, thank you very much.


Thank you. Our next question is from William Adams from FAMCO. Please go ahead.

William Adams – FAMCO

Good morning.

Steve Becker

Hi, Bill.

William Adams - FAMCO

I wanted to ask you first off, can you give us what the volumes have been running on Great Lakes for the month of January and so far in February?

Steve Becker

In terms of that particular answer, I’d like to give you a generalized answer because I don’t have the specific numbers in front of me, but I’d like to just preface that with the fact that about 75% of the paths are actually contracted, so what then ends up happening within the volumes is it depends on how those shippers actually utilize their contracts. So, the volumes are down quite significantly because someone who might have contracted to say, “I need access to pipeline capacity if it goes to 20 below,” when it was very warm, then either didn’t flow the volume or we saw a variety of patterns of flow on the pipeline.

So if we go one slightly lower layer, it is -- Great Lakes generally has long haul contracts. It has contracts coming out of storage from Michigan going east in the markets. It actually has storage contracts from Michigan going backwards to Minnesota and Wisconsin markets. So, the long haul volumes were very, very low.

There was actually very low at that end, but the gas coming out of storage was more weather-based and there was a little bit more activity on the bottom end of the system, so the key from our point of view is more how are we getting paid from a contracted capacity point of view, and then, subsequently, what ends up happening as we’re marketing that last amount of space, we’re actually competing with some of the customers if they’re not using their own space and that’s where the, in a very warm winter, it’s much more difficult for us to sell that last amount of capacity.

William Adams – FAMCO

Okay, then are you having to discount your rates, then, to sell that gas?

Steve Becker

There is some discounting that is involved, but it’s fairly modest and it depends on the -- often for the term involved, and so generally there is some amounts of discounting, but that’s not always been the case in the past.

Generally, when people are looking at it, they like to have it for the winter because if there’s a much more of a higher demand, there’s a lot of optionality and they’re paying us for getting access to that optionality within all of their mix of their portfolio.

William Adams – FAMCO

Okay, and then how much of your volumes on Great Lakes, your contracts on Great Lakes, will expire in November this year?

Steve Becker

Well, right now we’re at about a 75% level and we go down to a lower level in about the -- We’d be contracted at the 40% level, which leaves you roughly 60%. While that seems like an awful lot, what’s has happened in the past is Great Lakes was originally built and supported by ten-year contracts. As those contracts have expired, what people normally do is line up on an annual basis as both the supply and the market end and they kind of renew on an annual basis and that’s been consistently going on for a number of years.

This past summer, because of some of the uncertainty with the TransCanada mainline hearing, where a lot of the gas comes across on the TransCanada mainline into Great Lakes, people chose to contract a little bit smaller volume and that’s what led to our having some capacity through the winter.

So, the challenge for us trying to figure out what will happen next year is all these different factors we listed, like how do people react to the gas price, where’s the storage, but they didn’t know with the mainline hearing all during this timeframe.

At the end of the day, it’s usually -- they know they know they usually have to refill storage and that’s very critical, and they know it usually gets pretty cold in northern Minnesota, Wisconsin and Michigan, and so in trying to plan for that, they tend to contract based on longer term plans as opposed to what the current activities are.

But with the mesh of the short-term facilities with the long-term need, that’s where there’s a little more uncertainty for what will happen this November.

William Adams – FAMCO

Okay, so you’re saying that contract rates on November dropped to 60%?

Steve Becker

Dropped from 75% contracted to about 40% contracted.

William Adams – FAMCO

Oh, 40%.

Steve Becker

So it would leave 60% still left to contract.

William Adams – FAMCO


Steve Becker

And there’s a variety of paths and some are long haul, and so that’s a very generalized percentage, so it’s a very rough approximation.

William Adams – FAMCO

Okay. Should we think about that $10 million to -- you said you received on February 1st for Great Lakes, is that a good run rate for the first three quarters with the fourth quarter being dependent on how well you can re-contract the additional volumes that go off at the fourth quarter?

Steve Becker

I think it might be a better run rate for the first quarter, but Great Lakes has such a strong storage position that depending on how all those factors result, you start to get into all these different uncertainties and that’s a little tougher to get any more quarters beyond that.

William Adams – FAMCO

Okay, thanks for your help.

Steve Becker

We appreciate the questions, Bill.


Thank you. There are no further questions registered at this time. I would now like to turn the meeting back to Mr. Evans.

Lee Evans

I want to thank everyone for your participation here today. We appreciate your interest in TC PipeLines and look forward to talking to you again soon. Bye for now.


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

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