TC Energy Corp (TRP) 2009 Q2 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2009 Second Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Corporate Communications. Please go ahead, Mr. Moneta.

Thanks very much and good afternoon, everyone. I'd like to welcome you to TransCanada's 2009 Second Quarter Conference Call. With me today are Hal Kvisle, President and Chief Executive Officer; Greg Lohnes, Executive Vice President and Chief Financial Officer; Russ Girling, our Chief Operating Officer; Alex Pourbaix, President of Energy and Executive Vice President of Corporate Development; and Glenn Menuz, Vice President and Controller. Hal, Russ and Greg will begin today with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note that a slide presentation will accompany their remarks.

A copy of the presentation is available on our website at www.transcanada.com. And it can be found in the Investor section under the heading Conference Calls and Presentations.

Following their prepared remarks, we'll turn the call over to the conference coordinator for your questions. During the question-and-answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue.

Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Myles, Terry and I would be pleased to discuss them with you following the call.

Before Hal begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission.

And finally, I'd also like to point out that during the presentation, we'll refer to measures such as comparable earnings; comparable earnings per share; earnings before interest, taxes and depreciation and amortization or EBITDA; comparable EBITDA; and funds generated from operations. These measures do not have any standardized meaning prescribed by generally accepted accounting principles and are therefore considered to be non-GAAP measures.

As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide interested parties with additional information on the Company's operating performance, liquidity and its ability to generate funds and finance its operations. With that, I'll now turn the call over to Hal.

Thanks, David. Good afternoon everyone, and thank you for joining us today. Before I provide an update on our quarterly results and recent developments, I'd like to briefly speak to the recent changes in TransCanada's leadership team.

Effective July 16, Russ Girling was named Chief Operating Officer. Russ will have accountability for the physical and commercial operation of TransCanada's assets, including oil and gas pipelines, power generation and natural gas storage. He also assumes responsibility for the Corporation's capital investment program.

Alex Pourbaix continued as President, Energy and has assumed the additional role of Executive Vice President, Corporate Development; responsible for acquisitions, divestments, and the execution of major transactions in both Energy and Pipelines.

Our executive team remains focused on maximizing the long-term value of our existing asset base and prudently growing our large portfolio of blue-chip long-life energy assets. Today, we are in the midst of constructing over CAD 21 billion of secured low-risk projects that are expected to generate significant earnings and cash flow over the next four years, as these large projects come into service.

I'll take a few minutes to talk about our second quarter results and some recent developments before turning the call over to Russ and Greg for their comments.

As outlined in today's news release, TransCanada's net income for the quarter ended June 30, 2009 was CAD 314 million or CAD 0.50 per share. Our comparable earnings were CAD 319 million or CAD 0.51 per share.

Comparable EBITDA was approximately CAD 1 billion and funds generated from operations were CAD 692 million.

Our solid second quarter performance in the face of historically low power prices in Alberta and Ontario demonstrates the strength of TransCanada's business model and the quality of our existing assets.

Looking forward, our strong internally-generated cash flow and our prudent decisions to maintain TransCanada's financial strength means we are well positioned to fund our large capital program in 2009 and beyond.

Well designed and well executed capital projects are the proven means of creating significant shareholder value in our Pipeline and Energy businesses. And well structured prudent financing is essential. To that end, TransCanada successfully issued CAD 1.8 billion of common shares in the second quarter.

And although the carrying costs and dilution associated with this equity issue and other recent financings will have an impact on our financial results through the remainder of 2009, we are well positioned to generate strong long-term returns for our shareholders as projects such as Keystone, the North Central Corridor, Bison, Bruce A units 1&2, Kibby Wind, Halton Hills and Coolidge are completed and placed into service.

In the second quarter, we continued to make significant progress on a number of these initiatives. One of the most important developments in the second quarter was our decision to become the sole owner of the Keystone pipeline system through the acquisition of ConocoPhillips' remaining interest in the project for $550 million, plus the assumption of approximately $200 million of short-term indebtedness.

As part of the transaction, TransCanada will assume responsibility for ConocoPhillips' share of the capital investment required to complete the project, resulting in an incremental commitment of $1.7 billion through the end of 2012. This acquisition provides us with the unique opportunity to become the exclusive owner of an important oil transmission system that will play a vital role in transporting a growing supply of Canadian crude oil to the largest refining markets in the United States.

We believe the significant commercial support Keystone has received to date highlights the value it will create for our customers and our shareholders for decades to come. Russ will provide more detail on the Keystone project in a few minutes.

In Mexico, TransCanada entered into a contract to build, own and operate the $320 million Guadalajara pipeline. The pipeline is supported by a 25-year contract for its entire capacity with the CFE Mexico state-owned electric company.

The 500 million cubic foot per day pipeline will extend 310 kilometers from an LNG terminal now under construction near Manzanillo on the Pacific Coast, to the interior at Guadalajara, Mexico's second-largest city. Construction is expected to begin in 2010 with a targeted in-service date of March 2011.

During the quarter, TransCanada also sold the North Baja pipeline to TC Pipelines LP, our US MLP, and agreed to restructure the incentive distribution rates of the general partner. In return, TransCanada received aggregate consideration totaling approximately $395 million, including $200 million in cash and 6.4 million additional common units of the LP. As a result, TransCanada's ownership in TC Pipelines LP is increased to 42.6%.

The cash proceeds from this transaction will be redeployed to help fund our growth initiatives. And in the future, we will continue to examine portfolio management opportunities, including a significant ongoing role for Pipelines LP in the financing of our large capital program.

Turning north now to Alaska; in June, TransCanada and ExxonMobil reached an agreement to work together to progress the Alaska pipeline project. TransCanada has always maintained that the support of the state of Alaska, the U.S. and Canadian governments and the Alaska North Slope producers will be required to successfully advance the Alaska pipeline project. Our agreement with ExxonMobil is an important step towards that goal. Together, TransCanada and ExxonMobil have the experience, the expertise and the financial capacity to undertake this project.

We continue to move forward with project development activities, including engineering, environmental reviews, Alaska native and Canadian (inaudible) arrangement and the commercial work necessary to conclude an initial binding open season by July 2010.

Turning to our Energy business, earlier this month Bruce Power and the Ontario Power Authority amended certain terms and conditions included in the Bruce Power refurbishment agreement. The amendments are consistent with the original intent of the contract and recognize significant changes that have occurred in Ontario's electricity market.

In effect, the changes reinforce the fixed and floor price arrangements that are in place with the Ontario Power Authority which effectively eliminates Bruce Power's exposure to market prices on 100% of Bruce's output.

And finally in Energy, the government of Quebec recently approved construction of the fourth and fifth wind farms to be developed by Cartier Wind, which is owned 62% by TransCanada. Both phases are expected to be operational by 2012.

As I mentioned earlier, TransCanada is in the midst of constructing over CAD 21 billion of secured large-scale projects that are well within our proven capabilities. These projects are expected to generate significant long-term earnings and cash flow for our shareholders.

Construction of Phase I of the Keystone Oil Pipeline System continues and is expected to be completed by the end of the year. Overall, Phase I of the project, Wood River and Patoka, is now approximately 80% complete and is on schedule to begin line fill in the fall months.

On the Keystone regulatory front, earlier this year TransCanada filed an application with the National Energy Board to construct and operate the Canadian portion of the Keystone expansion, which will take crude oil to the U.S. Gulf Coast. NAB hearings are scheduled to commence September 15 and we would expect a decision by early 2010.

In the U.S., we're proceeding as expected with state and federal regulatory filings for the Keystone expansion.

Turning to gas; on our Alberta system, the first section of the North Central Corridor expansion was completed on time, on budget and at a capital cost of approximately CAD 400 million during this past winter. We're now approximately 50% of the way through that project with completion anticipated in first quarter 2010.

In our U.S. gas pipeline business, TransCanada's Bison project filed an application with the Federal Energy Regulatory Commission for the right to construct, own and operate the Bison pipeline; moving natural gas from the U.S. Rockies to a connection point on our northern border pipeline system.

And in Energy, work continues on the Bruce Power restart. While Bruce Power estimates the total capital cost of the project to be approximately CAD 3.4 billion, TransCanada's current view is that costs may exceed that amount by approximately 10%.

Despite that potential increase in capital cost, we continue to expect that the restart project will yield an unlevered after-tax return on total capital in excess of 10%. Refurbishment of Bruce A Units 1&2 is expected to reach completion by the end of 2010.

Construction of the 680 megawatt Halton Hills generating station just outside Toronto also continues. We are approximately 80% complete on that project and we expect the Halton Hills plant to be in service in the third quarter of 2010.

TransCanada also advanced construction work on the Kibby Wind Power project in the Northeast United States, including the installation of 22 turbines which is expected to be completed this summer. When the project is finished in late 2010, Kibby will have capacity to produce 132 megawatts of electricity.

Finally, the Coolidge generating station in Arizona has received the necessary permits and construction on that project will begin in August.

In summary, our capital growth projects continued to progress as expected during the second quarter. Going forward, we will continue to place a significant amount of effort into delivering these projects on time and on budget. Once completed, the highly predictable and sustainable earnings and cash flow from these projects will create significant long-term value for our shareholders.

I'll now turn the call over to Russ Girling, our Chief Operating Officer, who will provide additional comments on the Keystone project.

Thank you, Hal; and good afternoon, everyone. As Hal said, TransCanada agreed in the second quarter to acquire ConocoPhillips' remaining interest in the Keystone partnership for approximately $750 million and it will now own 100% of the Keystone pipeline. That transaction is expected to close in the third quarter of this year.

I'd like to take a few minutes to provide you with a review of the Keystone project, our toll structure and the expected EBITDA contribution and future upside potential with the project.

As you know, we have firm long-term commitments averaging 18 years for 910,000 barrels a day or 83% of the commercial capacity of the pipeline. That leaves approximately 180,000 barrels per day of capacity available for spot sales or further long-term contracting before we consider further expansions of this system.

The 910,000 barrels per day of long-term commitments Keystone has secured to date have two parts to its toll. The fixed portion of the toll recovers capital-related items. It is a take-or-pay toll so shippers pay this fixed portion of the toll for the contracted volumes, whether they're shipped or not. The fixed toll is adjusted for changes in capital costs for a capital-cost risk-reward sharing mechanism. Once the project is completed, and the capital costs are known, there is toll certainty for our shippers as the fixed portion of the toll does not change over the term of their contract.

The variable portion of the toll is charged on all barrels shipped. It is designed to flow through all actual operating and maintenance costs, such that there is no risk to Keystone for the variable expenses of operating the pipeline.

This fixed-variable toll structure was critical to our shippers and helped influence their decisions to sign up for long-term firm contracts on the Keystone pipeline. As you heard, we are well advanced in the construction of the first phase of the Keystone project to Wood River and Patoka and we expect to be line filling this fall.

We will start delivering oil in the first quarter of 2010 under an interim contract arrangement. The interim contract period is approximately one year and the firm capacity commitment during this period is about 220,000 barrels per day. The interim period is structured to allow for operational and commissioning issues to be worked out during the first year of ramp up.

The pipeline will have a nominal capacity of 435,000 barrels a day. We would expect volumes to ramp up closer to that capacity as the year progresses. At the end of the interim period, the long-term firm contracted commitments of 375,000 barrels a day to Patoka and Wood River become effective.

The extension to Cushing and the expansion is expected to be in service in Q1 of 2011, increasing the nominal capacity to 590,000 barrels a day and the firm contracted commitments also increased to 530,000 barrels a day.

Following that, the Keystone expansion to the U.S. Gulf Coast will increase the commercial capacity of the system to 1.1 million barrels per day by the end of 2012.

When the Gulf Coast expansion is in service, Keystone will have 910,000 barrels per day of take-or-pay long-term shipping commitments in place, averaging 18 years, representing approximately 83% of the pipeline's capacity.

And moving to cash flow; as you can see from this graph, Keystone's EBITDA contribution to TransCanada's consolidated results is expected to be very significant as we ramp up service over the next three and a half years.

The 2010 EBITDA contribution from Keystone is expected to be in the range of $150 million to $325 million, depending on the amount of volume shipped above the interim contracted level during the interim period.

Depreciation of the Keystone assets will be calculated on a straight line basis over a 35- to 40-year period. In the early years of the project, however, depreciation will reflect the ramp up of volumes.

As I said previously, when the Cushing extension is in service in early 2011, the firm contracted commitment rises to 530,000 barrels a day or approximately 90% of the capacity. Correspondingly, the minimum contracted EBITDA contribution rises to approximately $600 million, with the potential to approximately $700 million, depending on the volume shipped on the un-contracted capacity.

Based on current long-term contracted commitments, 910,000 barrels per day, Keystone is expected to generate a minimum EBITDA of approximately $1.2 billion in 2013, in its first full year of commercial operation, serving both the U.S. Midwest and the Gulf Coast markets.

If the volumes shipped are at the full commercial design capacity of the system of 1.1 million barrels per day, Keystone would generate approximately $1.5 billion of EBITDA.

In the future, Keystone can be economically expanded from 1.1 million barrels per day to 1.5 million barrels per day, in response to additional market demands. We believe that Keystone is well placed to capture a significant portion of this upside in the years ahead.

The next couple of slides that I have will help explain why we believe that. As you can see in this slide which shows the Canadian Association of Petroleum Producers, June 2009 update to what they call their moderate growth forecast; the oil sands production is expected to grow by approximately 1.1 million barrels per day by 2015 and approximately 1.8 million barrels per day by 2020.

Although the forecast shows the upgraded light component growing much slower when compared to the June 2008 forecast, the bitumen blend oil sands component which is in green on this graph has increased. This is consistent with the view that mining and (inaudible) projects that produce bitumen are more likely to be developed than upgrading projects under the current market conditions. This reinforces the need to develop new markets for heavy bitumen blends.

In the event that synthetic or upgraded crude production in Alberta grows in the future, Keystone will also provide enhanced access for that product and will provide those shippers with enhanced batch quality, compared to their current alternatives.

On this slide, Canadian imports are shown in the top right graphic versus the total foreign imports by PADD or Petroleum Administration Defense District. Current Canadian crude constitutes 75% of the imports to PADD II, the U.S. Midwest, but only 2% of the imports to PADD III which includes the U.S. Gulf Coast.

The first phase of Keystone will provide improved access for Canadian crude to refiners in the Midwest and the next phase of Keystone, which will provide direct access to Cushing which is in the lower part of PADD II, and will provide access to more refineries on route to the U.S. Gulf Coast.

The Keystone Gulf Coast expansion will provide access to the U.S. Gulf Coast with over 8 million barrels a day of refining capacity.

As you can see by the orange bar on this chart, approximately 6 million barrels a day of that 8 million barrel a day requirement is imported from other countries. After Keystone is expanded to the Gulf Coast, Canadian crude will still constitute only 11% of the imports to this, the largest market for crude in the U.S. market that has sophisticated refineries capable of handling Canadian light and Canadian heavy crudes.

U.S. Gulf Coast refiners have been concerned about the shrinking supply of heavy crude supplies from traditional sources such as Mexico and Venezuela. Keystone will provide direct access to a very secure source of Canadian crude.

When completed, Keystone will have access directly or through interconnecting pipelines, to over 4 million barrels a day of refining capacity in the U.S. Gulf Coast, of which approximately 1.7 million barrels per day has heavy oil refining capability. We believe that these markets offer significant potential for additional contracting in the future, on top of the existing long-term firm contracts that Keystone already has secured.

As a result, we are optimistic we can fill the 1.1 million barrels a day of commercial capacity we have today, and potentially grow further through low-cost expansions of this system in the future.

I'll now turn the call over to Greg Lohnes, our Chief Financial Officer, who will provide additional details of our second quarter 2009 financial results.

Thanks, Russ; and good afternoon, everyone. As Hal mentioned, earlier today we released our second quarter results.

Net income for the second quarter was CAD 314 million or CAD 0.50 per share, compared to CAD 324 million or CAD 0.58 per share for the same period last year.

Comparable earnings in the second quarter was CAD 319 million or CAD 0.51 per share, compared to CAD 316 million or CAD 0.57 per share for the same period in 2008.

The primary reason for the drop in comparable earnings per share is an 11% increase in the number of shares outstanding, as a result of common share issuances in the second and fourth quarters of 2008.

The proceeds of these share issues are being used to fund our CAD 21 billion capital program that is expected to contribute to significant earnings and cash flow growth in the future.

I will now briefly review the second quarter results for each of our business segments at the EBITDA level, beginning with Pipelines.

The Pipelines business generated comparable EBITDA of CAD 747 million during the second quarter 2009, an increase of CAD 33 million over the same period in 2008.

U.S. Pipelines comparable EBITDA increased CAD 22 million, primarily due to a stronger U.S. dollar and increased short-term revenues at Iroquois.

Canadian Pipelines EBITDA of CAD 511 million is comparable to the CAD 509 million reported in the second quarter last year.

The short-term financial outlook for the Company's Pipelines segment is not expected to be materially impacted by the downturn in the economy or lower natural gas drilling activity. The Pipeline assets are generally underpinned by contracts or earn a regulated rate of return.

Next some comments on Energy; Energy generated comparable EBITDA of CAD 301 million in the second quarter 2009, compared to CAD 260 million in the same period last year.

Western Power EBITDA for the second quarter 2009 decreased CAD 79 million, compared to the second quarter last year, primarily due to lower overall realized power prices.

Average spot prices are down by CAD 75 per megawatt hour over prices at the same time last year, driven by lower heat rates in the Alberta market.

To reduce its exposure to spot market prices on un-contracted volumes, as at June 30, 2009, Western Power had fixed price power sale contracts for 4,800 gigawatt hours or approximately 60% of planned sales for the remainder of 2009, and 6,100 gigawatt hours or approximately 40% of the planned sales for 2010.

Eastern Power EBITDA increased CAD 26 million compared to second quarter 2008. This was primarily due to increased earnings from Portland's Energy which went into service in April of 2009 and the Carlton Wind Farm at Cartier Wind which went into service in November 2008.

100% of Eastern Power's sales volumes were sold under contract in both second quarter 2009 and 2008 and will continue to be sold in 2009 and beyond under long-term power purchase arrangements.

Finally, in Canadian Power, TransCanada's proportionate share of Bruce Power's comparable EBITDA increased CAD 53 million, compared to second quarter 2008. This was primarily due to increased revenues from prior realized prices as well as increased output and lower operating cost as a result of fewer outage dates.

In addition to the revenues received pursuant to the contracted sales, Bruce B also recognized revenue under the floor price mechanism in place with OPA, which effectively eliminates exposure to market prices on 100% of the output. There were no more price revenues recognized in 2008 as the average Ontario power price exceeded the floor price.

100% of the output from Bruce A in second quarter 2009 was sold at a fixed price of CAD 64.45 per megawatt hour, compared to (inaudible) per megawatt hour in the second quarter 2008.

We're very pleased with the operational performance at Bruce Power year to date. I should highlight, however, that Bruce A will complete two planned outages beginning in September.

Turning to U.S. Power; comparable EBITDA in the second quarter was CAD 65 million, an increase of CAD 15 million over the same period last year. Stronger results reflect contributions from the Ravenswood facility and the positive impact of a stronger U.S. dollar, partially offset by lower realized power prices in the New England market.

At June 30, 2009, U.S. Power had entered into fixed price power sales contracts to sell forward approximately 3,800 gigawatt hours for the remainder of 2009 and 8,100 gigawatt hours for 2010.

Finally, in our Energy segment, natural gas storage comparable EBITDA was CAD 34 million in the second quarter, compared to CAD 6 million in the same period last year. The increase was primarily due to the lower cost of proprietary natural gas sold at the Edson facility as well as increased third-party storage revenues.

Despite lower power prices, Energy segment comparable EBIT results for the second quarter were up modestly. Additional generation at Cartier, Portland and Ravenswood played a part in this increase.

Turning now to corporate; corporate EBIT in the second quarter was a loss of CAD 31 million compared to a loss of CAD 26 million in the same period last year. This was primarily due to higher support service costs in 2009, reflecting a growing asset base.

Now looking at a few line items below EBIT on the income statement; second quarter 2009 interest expense of CAD 259 million, increased CAD 73 million compared to the second quarter last year. The increase in interest expense was primarily due to new debt issues of $1.5 billion and CAD 500 million in August 2008 and $2 billion and CAD 700 million in January and February 2009, respectively. In addition, U.S. dollar denominated interest expense increased due to the impact of a stronger U.S. dollar.

These increases were partially offset by increased capitalization of interest to finance the Company's larger capital spending program in 2009, as well as higher gains on derivatives used to manage exposure to interest-rate fluctuations.

Income taxes were CAD 97 million for the second quarter 2009, compared to CAD 126 million for the same period in 2008. The decrease in income taxes was primarily due to lower pre-tax earnings, as well as higher tax differentials and other (inaudible) tax adjustments in 2009.

Turning to the cash flow statement; funds generated from operations were CAD 692 million in the second quarter, compared to CAD 676 million in the second quarter 2008.

Capital expenditures and acquisitions in the second quarter of 2009 were approximately CAD 1.4 billion related primarily to a number of growth opportunities including the increased ownership position in Keystone as well as construction progress on Keystone and other projects.

Estimated capital spending over the three-year period 2009 to 2011, is approximately CAD 6.6 billion in 2009, CAD 6 billion in 2010, and CAD 4.7 billion in 2011. These estimates reflect the additional capital commitments associated with owning 100% of Keystone.

The estimated annual capital spend profile is subject to some movement within these years, particularly as we move through procurement and construction planning for the Keystone expansion.

TransCanada's financial position remains sound. At the end of the second quarter 2009, our balance sheet consisted of 49% debt, 4% junior subordinated notes, 1% preferred shares, and 46% common equity. We are currently managing the largest capital investment program in the Company's history. We are pleased with the quality of our capital projects and we expect these projects will generate significant earnings and cash flow as they come into service over the next four years.

We have raised approximately CAD 7.2 billion in debt and equity capital since November 2008. We have a manageable debt maturity profile over the next three years; approximately CAD 250 million remaining this year, and CAD 400 million in each of the next two years. These are very manageable numbers for a company of our size.

We have CAD 3.5 billion of cash on hand, along with additional committed revolving bank lines of CAD 3.5 billion.

We have an A rate credit rating with a stable outlook. Our working relationships with all three credit-rating agencies are strong.

Our 2009 capital program is fully funded and we're well positioned to fund our capital program in 2010 and beyond. We have the liquidity and capital resources to access the capital markets and we have significant debt shelves available.

We intend to use TransCanada's growing internally-generated cash flow, our dividend reinvestment plan and the issuance of long-term debt, supplemented by further subordinated capital if required, in the form of preferred shares or other hybrid securities to fund our existing capital program.

As demonstrated by the recent sale of North Baja, TransCanada will also continue to examine opportunities for portfolio management, including an ongoing role for TC Pipeline LP and the financing of our capital program.

That concludes my prepared remarks. I'll now turn the call back to David for the question-and-answer period.

Thanks, Greg. Just a reminder, before I turn it over to the conference coordinator, we'll take questions from the investment community first. Once we've completed that, we'll turn the call over to the media. With that, I'll turn it back to the conference coordinator for your questions.

Thank you. (Operator Instructions). The first question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thanks. I'm interested to get an update on TransCanada's views on the power markets in which they operate-- or you operate in. And also if you could give us any sort of indication at what levels of pricing your hedges are and how you might consider altering your hedging strategy going forward, given where the power markets are right now?

Sure, Linda. It's Alex. I'll give you a bit of an idea sort of where we see prices at for the balance of the year and then going forward. So out West, we're probably looking at something in the mid 50s for the balance of the year. 2010 probably right now around CAD 60, probably CAD 65 2011.

In New York, probably low 50s for the rest of the year, around $70 for 2010, around $75 or $76 per megawatt hour for 2011; New England; probably around the mid to low $40s for the balance of the year, around $60 for 2010 and around $65 in 2011; New York and New England obviously all being in US dollars.

Okay. And then your hedged pricing in those regions?

We're pretty leery about giving too much specific information. What I would say is our forward sales in Alberta are all kind of-- if you look at averages for those three years, they're probably in the average anywhere from sort of mid 60s to the low 70s.

We're much higher at Ravenswood for our sales, probably over those three years kind of in the range the low 70s up to 90.

And in New England our hedges are probably in the range of the mid to higher 70s.

Okay and then going forward; has your hedging strategy changed, given where the forward markets are now?

I'll tell from my perspective, I certainly look at it from the perspective-- where prices are right now on our main markets, I do not see there as being a significant amount of downside and I think in fact opportunities are skewed significantly to the upside. You look at Alberta and we're probably in 2010-2011 we're kind of looking at sort of a 10 heat rate in a market that has cleared historically for the last several years at around a 13 heat rate. So I think the prices for the balance of '09 probably represent fair value and represent where we would do deals.

We're going to still get off some volumes in 2010 and 2011, but I really don't see a lot of downside. I probably see more upside than downside to those forward prices.

Okay, great. Thank you.

Okay.

Thank you. The next question is from Carl Kirst from BMO Capital Markets. Please go ahead.

Hey, good afternoon, everybody and congratulations, Russ. A couple of questions, if I could on Keystone and the first is-- not that you (inaudible) the CAD 21 billion backlog here, but earlier we were thinking we might have some various-- season potential lateral to Houston. Can you kind of get a sense if those conversations are ongoing, if kind of the market conditions maybe have stalled that out or the fact that it looks like the forward strip now over 70 today, if those kinds of conversations have come back to life.

We actually never stopped working on those. Obviously the Houston market is a critical market for us. I think we've sort of thrown out numbers before of-- it costs us about CAD 300 million to get there. We'd like someone to underpin that. So that would likely be one of the refiners or a couple of refiners in that market. So those conversations are ongoing, Carl. And I would say that we're still two and a half or three years away from having the capacity at the Gulf Coast.

So given that we could build that lateral in a relatively short period of time, the urgency is not there yet, but I would expect over the next year or so that that urgency will pick up.

Okay, so I think maybe what was said prior was just sort of perhaps stay tuned for various open seasons. That's not something we should expect to develop at the end of this year; that more kind of a 2010 or perhaps beyond event?

I think that there's still-- I mean we're still going to look at open seasons over the next year to sell that capacity. As interest sort of peaks, we will go out for open season and so forth. I think initially where the market is at is they're looking at any additional capacity that we have to Patoka and Wood River, because that's sort of more sort of near term. So I would expect to see us having open seasons for that capacity relatively shortly. And then so for the Gulf Coast, that would be following on after that.

Great. And second question is just-- and appreciate the EBITDA color with Keystone as it's phased in; I just want to take a look at 2013, kind of where we are perhaps at full utilization-- this CAD 1.5 billion EBITDA and perhaps reconcile it to what we should be thinking about from an expected return level and kind of simple math-- if you assume sort of that 40-year depreciable life, you back out CAD 300 million of DD&A and you use a 35% U.S. tax rate. I'm kind of looking at kind of an after-tax unlevered return in the 6.5% range at full utilization, relative to the 7% to 9% that you guys normally talk about. And I didn't know if maybe I was somehow askew on that.

You have to walk through those assumptions again. You should get a number that looks like around 8% when you kind of walk through sort of that full utilization. You have CAD 1.5 billion of EBITDA. It kind of gets you in that range of an EBITDA multiple of about eight times. And usually you start out when you calculate that multiple of eight times, you're going to get a return that's something in excess of 8%.

So if you use a 60% debt, 7% kind of interest costs, I would say that you'd get a number that-- a run rate that looks like around 8%. So perhaps if you want sort of offline, you could walk through your assumptions with Dave or Myles and Terry and just compare notes. But I would expect you to get a number that looks like about 8%.

Great. I appreciate the color.

Thanks, Carl.

Thank you. The next question is from Andrew Fairbanks from Bank of America. Please go ahead.

Hey good afternoon, guys. I just had a question on Bruce, if I could; as you look at the realized price of the Bruce B Unit, it's CAD 70 during the quarter. It seemed a little strong to us versus history and certainly the spot rates in that market during the quarter. So I was wondering-- can you add some more color on that kind of realization. Did the OPA contract amendments have any bearing on that or what was really driving the strength there?

I'm happy to do that, Andrew. And we kind of figured we would get this question because it seems a little counter-intuitive and you're correct. It's very much related to the amendments of the BPRIA or the implementing agreement that we have with the Ontario Power Authority. And I guess the easiest way to think about this is- is this just-- it's obviously just referring to the Bruce B volumes. And if you think about it, you can divide the revenue stream from Bruce up into two categories now.

On-- the first category is what I would call the floor price volumes. So we have the floor price of give or take CAD 48 a megawatt hour and you can multiply that price by all megawatt hours produced by Bruce B or our share of Bruce B for the period. And then there's a second revenue stream-- not knowing over the last couple of years that we were going to get to a point where we were able to recognize the revenue from the Bruce B floor; the Bruce team has entered into a number of longer-term contracts to sell the output from Bruce B. Those contracts, in the context of the Ontario power market, those contracts are all contracts for differences, pursuant to which Bruce Power gets paid a fixed price and sells-- and they get paid a fixed price and pay the counterparty the spot price.

So if you think about it, over the last quarter, we've had very, very low spot prices in Ontario sort of in the range of the-- in the mid CAD 20 range. And most of the fixed price contracts I think the average price for that package of contracts which represents notionally about 60% of the output of Bruce B; the average sale price would be around CAD 60. So if you think about it, just to make things really easy; if the market price averaged CAD 30 for the quarter, under the contract for differences, our counterparties would have paid us CAD 30 a megawatt hour for all of the contract volumes, which was about 60%. And that's actually a pretty-- pretty right on to where we ended up this quarter.

So the net effect is that it resulted in a higher average sale cost for the quarter. Does that help?

Yes, that's very helpful. And that should be a formula, broadly speaking, that should apply over multiple quarters?

Yes, to the extent that we continue to have forward sales still in place, for the B volumes.

Got you. Great, thank you.

Thank you. The next question is from Bob Hasting from Canaccord Capital. Please go ahead.

Yes, just to continue on that because that's certainly an area of interest for me as well. Just this is only going to apply as long as you have the existing contract and presumably you wouldn't get those contracts today, so is it safe for modeling purposes to assume those just kind of run out, we should be using the floor price after that?

I think generally that's probably not a bad way to look at it. I think one of the things that I would say is that Bruce Power represents close to 25% of the power in the Ontario market. And it really does provide a very important service in providing longer-term power sales and giving liquidity to the power market. So it is possible you'll see us doing some more contracting as time goes forward. I think it's important to the market, to the government, but I think generally that's probably a reasonable way to model.

Okay. And speaking of the Ontario market where we've seen even Bruce Power have to shut down (inaudible) just because of the lack of demand and the weather and manufacturing I guess demand being down. You're getting protests now for-- or everybody is-- for new power plants and especially the (inaudible). What do you see as a risk to that market? Do you think we could just see everything sort of come to a standstill in terms of new projects?

I think generally, my view on the Ontario market is we've seen a pretty significant fall off in load-- certainly in industrial load, I think probably somewhere in the range of 1,000 to 2,000 megawatts of that load lost you could probably describe as permanent. And then some of the load loss is just related to the present economy and if things pick up, we'd probably expect to see some of that come back.

All being said, when I sort of look at supply-demand in the Province, I think it's very, very likely that the government is going to go through with their commitment to turn off the coal plants in the 2014 time period which I think will have some impact.

I think when you look at the RFPs that the OPA has out, I mean a lot of them are not so much to provide general supply, but rather to deal with the congestion problem in the market, Bob. I think particularly the Southwest GTA is-- some of it is for general power needs in the market, but a big part of it is that over the years sort of-- I would call the core of Toronto has lost the lion share of its power-generating capacity and it's very important for system reliability to get that plant built and that was similar with Portland Energy Center. So I think you're going to continue to see some of that.

I wonder, and I certainly think it's reasonable to see any RFPs that might be contemplated just for general supply, probably could be put on hold for probably a five-year period, just as a result of where we've seen demand go.

And would that have any impact on strategies for the feed-in tariffs?

Well, I can't speak for the government, but it does-- I think the government is going to have to be quite cautious as to how aggressive they are with respect to their renewable procurement. Because those feed-in tariffs-- there probably is not insignificant amount of power that can come on the grid over the next few years.

Okay. Thank you very much.

No problem.

Thanks, Bob.

Thank you. The next question is from Matthew Akman from Macquarie. Please go ahead.

Thank you very much. I just wanted to start with more of an update on Ravenswood, if I could, Alex. In the quarter, I wonder if you can give us any information on the financial contribution from Ravenswood.

We don't split out-- we don't split out individual plants. But I think what I could say generally is from a capacity perspective, Ravenswood delivered at or slightly above our expectations. From an energy perspective, it was a pretty disappointing or relatively disappointing quarter for Ravenswood as you probably know. The last I saw last week- New York was having the coldest summer in recorded history and that's had a big impact on spark spreads.

Demand is about where we expected it to be. We're hoping we get some summer here in the next couple of months though, because it has been a little bit of a disappointment on the energy side.

As I recall, when the transaction was announced, the capacity payments were going to be around 75% of the total EBITDA contribution?

Yes, I think that's generally a pretty good number.

Okay. And is that true probably going forward now, or might they be even higher, because it looks like the capacity market is looking up with the probably removal of [Poleti] from service and yet the energy market is obviously weaker.

We're pretty comfortable that the capacity market is going to turn out sort of at or above the kind of levels that we had talked about at the time we did Ravenswood. We don't see too many dark clouds on the horizon.

With respect to the energy market, I'm going to be pretty-- as I said, right now it's been a bit of a disappointment for us but it is such a unique situation with $3.00 gas and such incredibly cold weather. I don't think at this point I'm ready to sort of materially change our expectations on the energy contribution from Ravenswood longer term.

And on operating costs on the plant, I noted there was some talk of a strike there. Is that an issue from your forecast operating cost perspective or how do you see that playing out?

We have a-- we did-- we got fairly close. We had some pretty active discussions with the union. At the end of the day, we settled on a four-year deal with very modest salary increases that were within our expectations and what we budgeted for.

Okay, thanks for that update. And I just had one clean-up question on the financial side, probably for Greg. It's around the interest expense in 2010. And Russ talked about a more moderate contribution from Keystone in 2010 on the EBITDA front as it ramps up, which is understandable. But I'm just wondering whether you'll be expensing all of the interest associated with the debt for construction and progress that's been capitalized at this point or whether you'll just be expensing a portion of that in 2010 and then the full amount in 2011 when the more full EBITDA contribution comes on?

It's Glenn here. As far as capitalized interest, we would continue to capitalize interest on any assets that are not yet in service or are still under construction. So obviously as the different phases of Keystone start to come in, you will start to see more interest come into the income statement.

I understand that, but the first phase is a CAD 4 billion project and if you expense CAD 4 billion worth of interest or interest on CAD 4 billion of capital, and you only record half of the EBITDA or normalized EBITDA from it, then that's going to have an earnings impact. And I'm trying to figure out how that's going to play out.

I understand what you're saying and that's currently a discussion that we're having with our auditors on that, and determining what the right approach is because we are in a unique situation here with the phase in of the volumes as well as the phase in of the different legs to Keystone. So it is something we are looking at. But at this point, I don't have a specific answer for you.

Okay, thanks. Those are my questions.

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.

Thank you, good afternoon. The question is for Hal and it relates to TC Pipelines. In the last little while you've been a lot more vocal in the potential use of TC Pipelines. And just if we step back from a TransCanada perspective; how do you see your assets being held, really whether it's by business line or geography, across North America into the future?

Well, first and foremost I'd say TransCanada Corporation and our wholly-owned operating entity TCPL will continue to own most of them. When we look at pipes that might go into the MLP in the U.S., we always focus on the long-term stability and hopefully the diminimus capital requirement of anything that we put into the MLP.

We don't use our MLP as a development vehicle. We use it as a holding vehicle for stable secure long-term assets, the kind of thing that we think should really appeal to the MLP investor. And so as we look at different assets, we think about rolling them down into the MLP when they have those characteristics. And I think our track record would say that's what we have done.

Geographically in Canada, we don't have an MLP. There's not that sort of a vehicle existing in Canada so we would not foresee at this point, rolling significant Canadian assets into the MLP.

On the power side, private partnerships probably make more sense than some sort of public LP and of course Canadian tax law changes make all of that pretty straightforward I think, in Canada today. We're just going to keep things in corporate form.

One point I would make is we've never used our MLP as a collector of miscellaneous assets. We only acquire things in the MLP that would make sense to TransCanada and we very much view from a strategic point of view, anything in the MLP as being a TransCanada asset.

So part of all that strategy has been to increase our ownership share of the MLP to achieve the greatest possible alignment between TransCanada and our MLP unit holders. And as a result, we're at about 43% ownership of that vehicle today. But that's the way we look at the different assets that would go in there.

So where do you see the MLP going in the future from an ownership standpoint? Do you want to dilute down to a lower portion because you've had a smaller interest in the past?

Yes, no, there will be some movement up and down in our ownership level because there may be points where it's highly attractive to finance a transfer of assets using public equity, using a new issue of MLP units. And you could see us move down a little bit. There's no real reason that I'm aware of that we would want to avoid going above 50%, but I wouldn't expect that we would.

So I think you'll see us kind of swing up and down, roughly around the current ownership level that we're at today. We don't have any specific goal but, to achieve the greatest alignment, I generally would like to own more of the MLP rather than less.

Thank you.

Thanks, Andrew.

Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Thank you. Just with the financing plan as you look out to next year and the fairly residual equity needs, but you've been pretty conservative and despite the fact that you've got a lot of cash on the balance sheet; can you talk about some of the timing with respect to addressing the equity needs for next year and you mentioned TCLP, Greg, kind of at the end. Can you talk about how likely you want to use the LP versus potentially some of the other subordinated capital markets?

Yes. Of course we continue to monitor those markets for the best possible overall cost of capital to the Company. We've been quite successful the LP's responded very nicely to the North Baja transaction and the indication we've given that we would like to continue to use that vehicle; the yields come in nicely on that (inaudible) and the units are trading very well right now.

So I think we look at that favorably. The Canadian preferred share market is interested in non-bank product. As you've seen from some of the recent bank transactions, the coupon those spreads has come in significantly so it's become quite competitive and fairly close to where the MLP for a cost to capital.

So we're monitoring those two markets. We, as we did in 2007 with the hybrid transaction, the junior subordinated capital; we really like that product because it aligns nicely with our asset gap, so we're ramping up of course significantly on the U.S. asset side over the next three or four years and to offset that with additional U.S. debt and particularly where we do get approximately 50% equity treatment, but it's debt on our balance sheet as a very nice product.

We've been watching it closely. We've been seeing it rebound. There have been a couple of transactions completed. It's not a spot where we would step into that market at this point, but we would expect at some point in the next year to be able to look at that.

We're in great shape for the rest of this year and that gives us some flexibility around timing, as we continue to see markets improve for those kinds of products.

And I guess, just on timing; are you inclined with kind of how you financed and all the cash you've got to wait until next year? Would you move, say in the back half of this year just to kind of clean it up and to be able to say, we're done for equity needs through the end of 2010?

We, as we've indicated, are in--on a fully funded position here for 2009. We believe we have the luxury of time and the opportunity to monitor the markets. We'll be prudent but opportunistic as we see the market unfold here over the next year.

Okay. Just one last question; it's kind of a very small part. In the MD&A under gas storage, it talks about part of the higher earnings being the lower cost of proprietary gas sold at Edson. Can you talk about that, just with respect to kind of having locked in margins and therefore why the underlying cost of gas would move your earnings around?

Did you want to answer?

Yes, sir. It's Glenn here. You're right when we-- our standard practice there is to go in and lock in a purchase and lock in a forwarded sale at the same time, therefore, we've got a locked in margin. What you're seeing here is some impact on the weighted average cost of gas. So as we release it from the pool, there is some movement in that because what we cannot do is we're not able-- well, we're able to in our systems but not able to for accounting-- to match up specific sales against specific purchases. So although we have locked in a margin and it is profitable, the actual amount of profit will vary somewhat with the release of the weighted average cost of inventory.

Okay. Can you give a sense as to how much then of the CAD 28 million; are you essentially borrowing from future earnings, then?

No, I wouldn't say we we're borrowing from future earnings. There is a bit of a timing aspect; just hang on one sec, let me see if I can--

It's not a big amount. It was a factor in there, but by no means is it a big amount- marginal.

Okay. Thanks, Glenn.

Okay. Thank you.

Thanks, Robert.

Thank you. The next question is from Steven Paget from First Energy. Please go ahead.

Good afternoon, everyone; and just looking for a comment on the rationale behind entering the changes to the commercial agreements between Bruce Power and OPA please.

Sure, Steven. I think we really had a number of goals with respect to the agreement with the OPA and I think that is a contract that's already been amended I think at least a couple of times since we originally executed it. And as such, it's sort of become a living document. And I think from our perspective, and I think from the government's perspective, at the time we entered into this deal, no one was thinking about a situation where there was significant demand destruction in Ontario and that the market design started to produce a price that in no way, shape or form represented the actual cost of power in the market.

I mean it's very interesting. If you take a look at the market price for gas in Ontario right now, you have wholesale price of CAD 25 a megawatt hour, give or take. And then you have all of these costs which go into this global adjustment category which are new PPAs, wind, renewables; that right now the last couple of months have been averaging sort of CAD 35 a megawatt hour.

So you have this scenario where all in you have quite a reasonable price of power-- CAD 60 or CAD 65, but only a fraction of that is being delivered to generators through the wholesale market. And there was certainly a view on our part that that was an inequitable situation. It was causing us to grind through the CAD 575 million of protection we had on the 3&4 units. And then so that was really the rationale.

We wanted to accomplish three things, which I think we did. We wanted to get away from the CAD 575 cap which because of the wholesale destruction of the power price in Ontario; we were getting very close to as we got through Q1 and Q2. So we accomplished that.

The other thing we wanted to do at the time we originally negotiated that deal, and we put the floor in Bruce, there wasn't a lot of appreciation, I think by everybody, that it was going to become so problematic for recognizing that floor for accounting purposes. So we wanted to fix that so that we could, in the event we were in a year that we were relying on the floor, that we would actually be able to recognize that rather than the way that the accounting was originally working, we weren't recognizing it through either earnings or cash flow purposes. And at the end of the contract, we would recognize this giant lump sum balloon payment which just really, not only was not the intention of the parties, but really just didn't make sense to anybody. So we were able to fix that.

And the final thing we did was at the time we did the deal, the thought of the supply-demand balance in Ontario getting to such a point that you would actually, the ISO would be directing nuclear plants with a CAD 10 marginal cost to production to turn off; was sort of inconceivable and not something that anyone really gave any credence to. But that is where we got to. So the third negotiated provision which I think is material, is that we now going forward, will receive deem generation in the event that the ISO-- we need to shut down one or more of the units because of excess supply in the Ontario market, we will be paid by the OPA as though that power was actually available and delivered.

So those were the three goals. I think the government, Bruce did a great job of explaining to the government the rationale for those changes and I give a lot of credit for the government for appreciated that those were things that really needed to be dealt with. So at the end of the day, we achieved it and I think it's a pretty good outcome.

Well, you've just given the Master's class on power accounting; so thank you.

Thanks, Steven.

Anything else, Steven?

No, no thank you. That's my question.

Okay, thanks.

(Operator Instructions). The next question is from Ross Payne from Wells Fargo. Please go ahead.

Yes, real quickly, I just want to make sure I'm clear on this. Has the open season all the way into the Gulf been complete or is that something you're anticipating?

The first open season is complete. We have 380,000 barrels a day of contracts against a capacity of 500,000 barrels a day. So we have 120,000 barrels a day left to sell. And we will look for opportunities to sell that over the coming years.

Okay. And can you speak to who some of the larger player there are.

Yes, the ones that have publically announced that they are shippers on that piece of the pipeline include Valero, Conoco, CNRL; and I think those are the only ones that have publically announced their position. There are several others and they're large either producers or refiners, but those are the ones that have publically announced that they're major shippers on our pipeline.

Okay, thanks. Also with a decreased heavy to sweet differential that we're seeing right now; is that impacting the attractiveness of contracting the remaining barrels, in your opinion?

I believe that the differentials are tight right now because we are-- both current and future-- are because we're building this pipeline, so I'd expect that tightness to probably continue into the future. But at the end of the day, bitumen or heavy oil is what's going to be produced in Alberta and it's got to find itself a market and the logical market is the Gulf Coast.

So I think that there'll still be sufficient economic rationale to contract those barrels to the Gulf Coast. The production is moving forward and the available supply is declining in the Gulf Coast. So I know that those parties are actively talking to each other every day and I suspect one of the major components of that discussion is how are they going to set the differential; is it going to be fixed or is it going to be floating and how are they going to split that difference between producer and refiner?

And what we've seen in a lot of cases is where the producers and refiners have come together in either a joint venture or some sort of contractual structure that allows them to figure out they're going to share that.

Okay, and one final question, just conceptually; you've got two proposed lines, one from Alaska and one from the North Shore of Canada. I was just curious why those two could not be tied together in some kind of fashion-- just maybe operationally that may not work, but what are your thoughts there?

It's Hal here. First of all, hydraulically it doesn't make any sense because the line from Alaska will completely fill a 48-inch pipeline of really the highest pressure design that is practical. So if you put a BCF and they have Mackenzie in that line; you would back out of BCF of Alaska and that isn't what the Alaska shippers would want.

Secondly, there is a regulatory reason and that's that it's very difficult to build a pipeline from Prudhoe Bay to Inuvik, which is where the Canadian Mackenzie line starts. The National Wildlife Reserve NWR and a National Park that was created on the Canadian side of the border, make it virtually impossible to build on on-shore pipeline.

The alternative is to build offshore in the Beaufort Sea for about 300 kilometers and that just becomes prohibitably risky, given the movements of the pack ice that can blow in or blow out at relatively short intervals. We've looked thoroughly at that.

There's a third and political reason and that's that the gas at Prudhoe Bay really owned by the state of Alaska and the state of Alaska would like to see this infrastructure built through the state of Alaska. We've looked at all these different options and there's not really any significant (inaudible) for anybody by combining the projects. It costs a certain amount. Both projects have reached full economy of scale and so it's really neutral and therefore the state's political considerations play a significant role.

Okay. And finally, how firm is the moving forward on this project-- on the Alaskan pipeline at this point?

Well there's a number of reasons why it could or could not move forward but I think a very significant one is that the producers at Prudhoe Bay would point out that the most sensible time to stop re-injecting all that gas and start moving some of it to market is in that 2015 to 2018 window. That has been the consistent position of ExxonMobil for quite a few years.

And so we've always looked at that as a determining factor in addition to market demand for the gas, that there's a point in the depletion plan for Prudhoe Bay when it just makes sense to bring that gas to market.

Okay, that's very helpful. Thank you.

Thank you.

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.

Just a quick follow up and it's really for Hal. Have you had a chance to meet with Governor Parnell since he was sworn in just about a week ago?

Yes, I have. We went up and we did meet with him and we had a good discussion about the project in Anchorage and my conclusion out of that is the state's direction on this project remains unchanged and Governor Parnell is very supportive of where the state Department of Resources is taking it.

And obviously you see your agreement with Exxon as being able to propel this along a bit further than in the past?

Well, as I said in my prepared remarks, we need all five parties to really come together to make this go. And maybe there are six parties, actually I can think of. And so the state of Alaska is a critical player in how it will unfold. ExxonMobil is the largest reserve holder in the state of Alaska. We have those two parties together now, TransCanada, the state of Alaska and ExxonMobil. That's a pretty strong alignment, I think.

We look forward to the day when the other two Alaska producers are able to join the project and of course we continue to work on Canadian and U.S. federal government support; so a lot of different players, but I think the things are lining up the way we would like them to.

Thank you.

Thanks, Andrew.

Thank you. The next question is from Steven Paget from First Energy. Please go ahead.

Very quickly as we are into the second hour; is there some pressure from other uncommitted shippers along the Mackenzie Valley to have the pipeline on so that volumes that are basically have been undrilled but have shown up significantly on some testing, could come to market?

And you're talking in Alaska?

Down the Mackenzie Valley; there have been drills--

Okay, sorry. I understand now. Yes, there have been significant volumes discovered south of Norman Wells and the pipeline would of course intend to gather that gas and bring it down and into the Alberta system. But it's not determinative, Steven-- determinative of volumes for those that are in the Mackenzie Delta and those are the ones that we're very focused on and in discussions with the government of Canada. We really need the Northern volume in order to make the whole project go.

And then of course there is expansion capacity in different ways to accommodate a gas either as at the [Coalville] Hills area north of Norman Wells or the Husky-operated fields to the South.

Thank you. That's the end of my questions. Thank you.

Thank you, Steven.

And it's Glenn here; just in response to I believe it was Robert's question around the cost of gas on storage. We have checked that and of the amount recorded for storage it was only a couple of million dollars related to this cost of gas. And it really only came up this year because we had some proprietary gas sales, whereas last year we had no proprietary gas sales and it was all third-party revenues.

Thank you. (Operator Instructions). There are no further questions registered at this time. I would like to turn the meeting back over to Mr. Moneta.

Great; thank you and thanks to all of you for listening in what I know is now late in the afternoon in the East. We very much appreciate your participation in the call this afternoon and we look forward to speaking to you again soon. Thanks and bye for now.

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