Sea Limited (SE) Q2 2009 Earnings Report, Transcript and Summary

At this time, I would like to welcome everyone to the Spectra Energy second quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer Session. [Operator Instructions]. I would now like to turn the conference over to Mr. John Arensdorf, Spectra Energy's Chief Communications Officer.

Welcome to Spectra Energy's second quarter 2009 earnings review. We're very pleased that you have been able to join us today. Leading our discussion today will be Greg Ebel, our President and Chief Executive Officer, and Pat Reddy, our Chief Financial Officer. Both Greg and Pat will discuss our quarterly results and provide more color around our strategic plans to enhance the value Spectra Energy delivers to its shareholders. We'll then open the lines for your questions. Before we begin, let me take a moment to remind you that some of the things we will discuss today concern future company performance and include forward-looking statements within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements. So, you should refer to the additional information contained in Spectra Energy's Form 10-K and in our other SEC filings concerning factors that could cause these results to be different from those contemplated in today's discussion. In addition, today's discussion includes certain non-GAAP financial measures as defined by SEC Regulation G. A reconciliation of those measures to the most directly comparable GAAP measure is available on our Investor Relations website at spectraenergy.com. With that, I will turn the call over to Greg.

As you can see from our earnings release this morning Spectra Energy delivered solid ongoing second quarter results of $141 million or $0.22 per share, very much in line with our expectations. While earnings saw the impact of lower commodity prices and a weaker Canadian dollar this quarter, our fee-based businesses, storage, transmission, distribution, and Canadian gathering and processing performed very well serving customers, markets and shareholders. In fact, after removing from ongoing earnings, the effect of commodity price and exchange rate changes, we saw a quarter-over-quarter and year-to-date EPS growth of about 8%. That's solid growth from expansion projects at our fee-based businesses. As you know, the overwhelming majority of this year's EBIT will come from these fee-based businesses with less than 20% sensitive to commodity prices. Oil prices appear to have rebounded from their first quarter lows, and as the economy recovers I expect we'll start to see some improvement in NGL prices as the year advances. The Canadian dollar is currently less than $1.10 to the U.S. dollar compared with $1.20 we assumed in our forecast. This quarter we continued to execute well on the capital expansion plans and so far this year we brought four projects into service, on time and on budget, totaling over $300 million in CapEx. As we mentioned last quarter, we brought the West Doe II project into service in March which provides access to the developing Montney play in Western Canada. The third phase of West Doe is scheduled to come into service later this year. In April, we completed the Steckman Ridge storage facility in Pennsylvania, which brings 12 billion cubic feet of new storage into service and Steckman is strategically situated between new natural gas supplies from the East, Mid-Continent and Rocky Mountain areas and is really close to existing interstate pipelines serving the Mid-Atlantic and New England states. In late June, we also brought the Sarnia project in Ontario into service. This storage project will add over 5 Bcf of storage capacity to our portfolio. Finally, in July we completed the first phase of an additional cavern at Egan storage, adding a further 5.5 billion cubic feet of storage capacity at the Louisiana facility. These projects are in service, providing earnings and cash flow now and our remaining 2009 projects are on track for successful completion. We'll talk about those projects later, but first let's take a look at our track record of successful project execution. From 2007 through 2009, we will have placed into service expansion projects totaling more than $3 billion with the majority of these already completed. These projects will contribute annual EBIT of $380 million for a combined return on capital greater than 12%, higher than our 10% to 12% commitment. Let's take a look at our entire slate of 2009 projects and which I think is a pretty impressive array of organic growth opportunities. By year-end, we expect to place into service 10 major projects totaling approximately 650 million in capital. These fee-based projects will deliver total annual EBIT contribution of about $80 million, $35 million that we'll realize this year and an incremental $45 million next. Again, we expect returns on capital employed for these projects to be slightly above the high-end of our 10% to 12% range. Looking at our expansion opportunities for 2010 and beyond, this next slide is one we like to use regularly with you to keep you apprised of the progress we're making on long-term growth plans. You will notice that we have now placed into execution several more 2010 and 2011 projects, and I think it shows we're vectoring in on a 2010 capital expansion plan in the billion dollar range. These opportunities reflect the strong demand for infrastructure projects, both in Western Canada and the Northeast US. We continue to make good progress on additional projects, which leads us to believe that we could also see opportunities to spend up to a billion dollars in 2011. We'll have to wait and see if all of these development projects proceed as expected, but the outlook is promising at this point in time. There are two major projects I do want to call out in particular. Our TEMAX, TIME III project, the $700 million expansion which will start adding EBIT during the second half of 2010 and a series of projects in Northeast British Columbia in the Fort Nelson region, which will represent a total investment of up to a billion dollars. A portion of these Fort Nelson projects will be brought into service each year between 2010 and 2012 incrementally adding earnings and significant cash flow. Let's take a closer look at these two areas of activity. We will start with Texas Eastern. This map details our project to move Rockies gas into Northeast markets and the tremendous opportunities we're taking advantage of in that region. As you can see, Rockies gas is moving to Ohio on the [rex] pipeline with approximately a B-and-a-half to expected to arrive this year. Spectra has a direct connection to this supply and through our Texas eastern pipeline, we're connected to large East Coast markets that are looking for Rocky supply for their portfolio. The key for us is to figure out who wants this gas, where they want it and when they wanted it. We've done that through the following projects. We placed TIME II into service in November 2008, delivering 150 million cubic feet a day of new capacity from Lebanon, Ohio, to New Jersey. Northern Bridge is currently under construction and will come into service later this year with another 150 million cubic feet per day from Clarington, Ohio, to Oakford Pennsylvania storage. The TEMAX project which serves a number of good customers including ConocoPhillips and will provide capacity of 395 million cubic feet per day to move gas from Clarington to connect with both Texas Eastern and Transco Station 195. Finally, TIME III which will provide a further 60 million cubic feet per day of service from Oakford Storage to Texas Eastern and again Transco 195. Both TEMAX and TIME III are scheduled to be in service in late 2010. Collectively these projects will move about half the Rockies supply that's expected to arrive in Ohio. Other regional pipelines are been proposed and are likely to construct about 400 million cubic feet per day of take away in this same timeframe. This group of projects provides the right solution for customers by utilizing existing infrastructure to meet the market needs and virtually eliminates the need for an expensive bullet line to the East. Another area of great opportunity for us is in Fort Nelson, British Columbia. Our Western Canadian assets are strategically concentrated in the high growth conventional and tight sale resource play in the region. We have a multi-phase expansion program currently under way to increase gathering and processing capacity in Fort Nelson to accommodate the increased volumes coming from the Horn River. Our assets are located squarely in the middle of this prolific region of British Columbia which recent estimates suggest could hold as much as 500 trillion cubic feet of gas. Responding to strong producer interest and activity, we held an open season for incremental service which has resulted in firm contract commitments of 790 million cubic feet per day of service for ten producers. These firm, fee-based gathering and processing contracts will provide revenue from demand charges. So we have no commodity exposure. Our Fort Nelson expansion represents not one single project, but a series of projects that will come into service between 2010 and 2012. Typically, earnings aren't generated until completion of an entire project, but this multi-phased expansion will deliver incremental earnings and cash flow each year as the individual projects are brought into service. While still in the early stages, between now and 2012, we are committed to investing up to a billion dollars on these projects and returns on these projects will be at least as attractive, if not more so than those we have seen on our investments over the last three years. While we had a good quarter and the earnings results were in line with expectations, what I am really pleased with is the continued progress and execution of our fee-based expansion project projects in both the US and Canada. Finally, we were also able to use our financial flexibility and our continuing good access to capital markets to close and finance the acquisition of the Ozark assets through Spectra Energy Partners. Ozark is an excellent addition to our suite of pipeline assets and really does expand our reach into the important supply region of Fayetteville Shale and the Arkoma Basin. You will hear more about this on Spectra Energy Partners call tomorrow. Now let me turn the call over to Pat who will review the quarter results in greater detail. Pat?

Well thank you Greg and good morning, everyone. As announced earlier today, Spectra Energy reported second quarter 2009 earnings of $140 million or $0.22 per share compared with $295 million or $0.47 per share in the second quarter of 2008. After removing the effect of the special items and discontinued operations, our ongoing earnings for the quarter were $141 million or $0.22 per share compared with $276 million or $0.44 per share last year. Let's take a look now at our performance by business segment beginning with US. transmission. U.S. transmission had a very good quarter, the segment reported second quarter EBIT of $234 million compared with $244 million in the second quarter of 2008. However, the 2008 quarter included a $31 million special item related to a customer bankruptcy settlement. So, on an ongoing earnings comparison, the 2009 second quarter was up $21 million. This 10% EBIT increase at U.S. Transmission was primarily a result of the strong earnings from expansion projects as well as lower project development costs during the quarter. The second quarter earnings were partially offset by lower gas processing revenues as a result of lower prices and volumes and lower equity earnings from our non-consolidated subsidiaries. The lower gas processing revenues are consistent with our 2009 plan. You will recall that in early 2006, Texas Eastern increased its processing volumes after Hurricane Katrina closed a third-party owned gas plant. That plant didn't come back online until the second half of 2008. As a result of these extra volumes and relatively high commodity prices last year, the 2008 quarter includes much higher than normal processing revenues. This quarter's strong earnings from expansion projects reflect the fact that we placed $1.5 billion of new projects into service last year, projects like Southeast Supply Header, Maritimes Phase IV Ramapo and Time II, and the Gulf Eastern expansions are providing significant EBIT contribution this is year. Let's now turn to Distribution. This segment reported second quarter 2009 EBIT of $40 million compared with $54 million in the second quarter of 2008. Excluding the $8 million effect of the decline in the Canadian dollar and an $11 million charge to reflect a regulatory settlement of prior year earnings, distribution EBIT would have increased $5 million this quarter. When you take out the two items I mentioned, distribution had a good quarter, primarily a result of higher storage and transportation revenues. I will take a minute now to give you a little more background on the regulatory settlement. Union Gas and its customers agreed to a settlement which preserves the incentive regulation framework through 2012 with no off-ramp for excess earnings, but it changed the terms of the sharing mechanism for earnings exceeding 300 basis points above the benchmark return on equity. Under the revised terms, Union Gas keeps the first 200 basis points; then shares the next 100 basis points on a 50-50 basis with anything above 300 basis points going 90% to customers and 10% to Union Gas. This settlement was retroactive to January 1, 2008. The $11million charge this quarter reflects the portion of the settlement applicable to 2008 earnings. I should note that this settlement does not apply to our favorable unregulated storage decision which we received a couple of years ago and has no effect on these unregulated storage revenues. Now, let's move onto Western Canada. Western Canada reported second quarter EBIT of $58 million compared with $91 million in the second quarter of 2008. Excluding the $10 million effect of the weaker Canadian dollar, earnings were $23 million lower than in 2008. Improved results in the base gathering and processing business, due to stronger activity in the Fort Nelson and Grizzly Valley areas, were more than offset by lower Empress earnings, primarily as a result of lower frac spread. The Empress frac spread this quarter averaged almost $5 compared with just over $8 last year. Let's turn now to Field Services. Field Services reported second quarter 2009 ongoing EBIT of $24 million, compared with $216 million in the second quarter of 2008. This decrease in earnings was primarily driven by lower commodity prices. During the second quarter of 2009, crude oil averaged approximately $60 per barrel, compared with $124 per barrel in the second quarter of last year. The relationship between NGL prices and crude oil averaged 44% in 2009, compared with 50% in 2008 and NYMEX natural gas averaged $3.50 per MMBtu, compared with almost $11 per MMBtu during the same period last year. The decline in commodity prices was partially offset by lower operating costs at DCP Midstream as a result of successful cost reduction initiatives and lower losses on non-cash, mark-to-market hedges used to protect distributable cash flow at DCP's, MLP. Now let's turn to other, which is primarily comprised of our corporate costs and captive insurance. For the second quarter, other reported ongoing net costs of $12 million compared with net costs of $28 million in the previous year's quarter, primarily due to lower corporate and benefits costs. A portion of this reduction is due to timing differences quarter to quarter and we will still expect other to be about $85 million for the full year. The next slide shows several important additional items. Interest expense for the second quarter was $146 million compared with a $149 million for the second quarter of 2008. This decrease is primarily due to the effects of the weaker Canadian dollar offset by higher long-term debt balances. However, at June 30, our debt balances are about $800 million lower than we projected in our plan resulting in significant interest savings year-to-date and we currently expect this favorable trend to continue. Our effective tax rate this quarter was 30% unchanged from the second quarter of 2008 and consistent with our ongoing annual forecast. As mentioned earlier, the Canadian dollar was weaker during the second quarter of 2009. The overall effect on net income was about $8 million compared with the second quarter of 2008. We have been actively focused on our balance sheet and as a result our debt to total capitalization ratio has improved. As of June 30, it stood at 57%, down from 62% at the end of last year. Our total credit facility capacity as of June 30 was $2.6 billion with available liquidity of more than $2.5 billion. The next slide will further detail Spectra Energy's very healthy liquidity position. As you can see here, our liquidity is underpinned by four separate credit facilities totaling about $2.6 billion. As I stated, our available liquidity at June 30 is above $2.5 billion, more than adequate to support our operations and current expansion program and an additional $800 million increase over last year. This strong liquidity position will allow to us take advantage of strategic opportunities that may arise. We continue to have good access to the commercial paper market at very attractive rates although with the amount of cash we have on our balance sheet, we're currently not issuing commercial paper. In Canada, we continue to see good availability of longer term debt at reasonable rates. We've had strong access to the capital markets since the beginning of the year and this next slide shows in detail all the debt and equity deals we have closed. In May, we completed two joint venture financings at favorable rates at both Maritimes in Northeast and Gulfstream and we completed the equity issuance at Spectra Energy Partners. These combined with the Spectra Energy equity issuance in February has positioned us extremely well with about 1.2 billion of net proceeds. This means we have the flexibility to choose when we want to go to the long-term debt markets. We can opportunistically access the debt markets for our remaining joint venture financings and can access the Canadian debt markets when we can do so at favorable rates. We're very comfortable with our financial position and are pleased with the successful execution of financing activities we have been able to complete in the past few months. With that let me turn things back over to Greg.

Thanks, Pat. At the halfway point in the year, I feel very good about where we are. During a period of economic uncertainty, our core fee-based businesses are providing steady profitable growth, stable cash flow from those businesses will enable us to continue to create value and pay an attractive dollar per share dividend. We're well-positioned for future growth beyond '09, and thanks to our proximity to strong supply basins, emerging shale plays and the high growth demand markets. We have another advantage, the natural gas is clearly an important part of the solution to our energy security and climate change issues. It is clean, domestically abundant, reliable, and we're working hard to ensure that it gets the fair treatment it deserves in any climate change and energy legislation. We'll maintain our investment grade balance sheet and the financial flexibility to respond to opportunities. As you would expect, we're managing our costs and fully expect to meet our $50 million cost reduction target this year. Combined, these factors underscore our ability to execute on our plan and deliver the operational and physical return targets we have committed to you to achieve. With that, we would be happy to take your questions.

Carie, would you please give instructions to the participants on how to ask questions.

(Operator Instructions). Your first question comes from Anthony Crowdell with Jeffries.

I just wanted to follow up on interest expense. You provided 2009 key assumptions first quarter or end of fourth quarter '08. You're looking at 2009 interest expense about $680 million. Right now you're roughly shy of $300 million. I want to know, are you seeing capital spending levels significantly lower than expected or should we still look at the 680 as where you end up in the 2009?

Anthony, thank you. This is Pat. Our growth CapEx for the year is actually going to be more in the $600 million range, so a little bit higher than the $500 million that we talked about in our guidance, but nevertheless we feel like the fact that we're a little below 300 million six months into the year on interest expense and it wouldn't be unreasonable to double that or annualize it, and expect just to come in closer to 600 million for our savings on total interest expense this year of about $80 million.

Your next question comes from Lasan Johong with RBC Capital Markets.

A couple questions. Maybe I missed it, but, Greg, did you mention CapEx numbers for the rex projects, rex offset projects you were going to do and is the CapEx at Fort Nelson still about a billion dollars to 2012?

The TEMAX group of projects runs around $700 million. I think I mentioned that, but that's what that number would be. Some of that spent in terms of TIME II, but 700 is a good number. And yes indeed, we see about a billion dollars worth of opportunity in the Fort Nelson region. Obviously, I see that more backend loaded than front-end loaded, but that's the type of number I would use through 2012.

Then returns 12.3%, that's really juicy and nice. Are we going to expect to see that on these new projects that you mentioned?

I would expect the TEMAX region of the world is a very competitive one, but I feel good that we should be able to realize those types of returns. Frankly, in Western Canada, I would be disappointed if we didn't do a fair bit better than that 12% type upper end of the target.

You had mentioned fee-based revenues, but just as an example a lot of E&P companies are cutting back CapEx spending and they are curtailing drilling. That means in theory at least you are going to see a significant reduction in new wells coming online and wouldn't that therefore then impact your fee business in terms of not enough gas to gather and process or is there some sort of minimum threshold that it's kind of a minimum take or pay type number?

Two different pieces there. The fee-based side of our gathering processing, that's really in the Canadian business. So those folks sign up for long-term contracts, so again that gives us confidence about the billion dollars spend and more importantly the revenue associated with that capital. In the United States through DCP, our joint venture with Conoco, we'll have to look closely as to whether or not we'll need to spend as much capital there. They spend and it is done by their own cash flow. They spend $500 million a year, call it in terms of capital, and we'll have to see. There is no doubt volumes being processed there are down from what we had predicted, and you know well about the rig count issue, but we'll have to see. You're seeing a lot of wells laid down, but let's not forget that from a CapEx perspective, the buyers on infrastructure are often looking for long-term type scenarios for supply problems that they have or supply needs that they have, and that's what really drives the bigger infrastructure build or the fee-based business if you will.

Do you have a minimum fee or minimum revenue that you collect from the producers in the U.S. regardless of whether they actually produce and deliver the gas for processing or not?

No, it depends. There are thousands and thousands of contracts at DCP. There are some fee elements to that. There is a fee business that accounts for about 10% of the margin at DCP. For some contracts, there is a minimum threshold, but well as you have seen with the earnings, we're directly impacted by both volume and 60% of the margin is percent of proceeds. So you've got to process that gas and then take your residual gas and your proportion of the NGL fill.

When do you kind of see an economic recovery happening in your minds?

Well, from our perspective it looks like we'll see some growth next year, perhaps not as optimistic in the last half of this year as some other folks. Until we see job growth pick up as opposed to just slow and decline, I think it is pretty tough to see anything, but anemic growth. Our focus is really that, look, the markets that we serve from what we're seeing, it looks like over the next ten years you're going to see about 3% growth in natural gas demand versus about 1.6, 1.7 for the rest of the lower 48, and that's what I am really focused on in terms of the long-term growth opportunities. In the short-term, there's no doubt until you see good economic growth that still hurts DCP, but the growth side of the business is really focused on the long-term need for natural gas which I think continues to be very strong.

Your next question comes from Carl Kirst with Carl Kirst with BMO Capital.

A couple of just clarifications. Greg, on the billion dollars of spend in 2010, you're specifically referring to the billion dollars of growth spend, right, so we're kind of looking at total CapEx now more in the 1.5 range, kind of the way it had been in prior?

That would be fair. Yes, I was referring to expansion CapEx.

With respect to the 700 million of TEMAX and TIME III, is that all now fully committed?

Yes, in particular the big counterparty there is obviously ConocoPhillips.

The third question was really just more revisiting Union Gas, I think you guys gave good color on the settlement. My question is more on the storage. What currently is the market-based rate storage environment up there and trying to get a sense of that. I guess storage market has changed over the last twelve to eighteen months with lower gas prices, trying to look at what perhaps our incremental pick up is over the next couple of years as you guys get more and more of the revenue?

Carl, maybe the way to think about that is to think about the second quarter where we had about $25 million of revenue from storage and transportation, and of that about $6 million related to the storage decision that gave us some outside incentives. So that kind of gives you a little bit of scale, and I think that will continue to grow because the storage market continues to deregulate at 25%, and so over the next couple of years through 2010 that should grow somewhat.

We're currently retaining 25% this year, is that correct.

No, we are at 50%.

We are at 50%.

We are at 50. Okay.

Your next question comes from Faisel Khan with Citi.

With regard to your growth projects for 2009, all the capital dollars you guys have laid out in your appendix or in your slides, has there been any change to those numbers over the last six months on any of these projects, are they all pretty much coming in online on budget?

In totality, we are pretty much online on budget. You always have some that are a little over and some that are little under, but feel very good that's where we'll end up about 650. Remember, Faisel the project cycle runs anywhere from 12 to 24 months, right. So you lock in a lot of costs, so you don't take on that risk just like you do with the revenue. So, if I think perhaps your question might partially also be around improvement in costs for steel and things like that. We're seeing some of that, but that's really going to impact projects going forward. Whether that really has an impact on return, I am a little skeptical, neither negative nor positive, just it's a competitive marketplace out there. So whatever we pick up and still things can end up going through to rates ultimately, particularly in the competitive areas.

On your Northern Bridge project, kind of connecting going from Clarington to Oakford. Once that expansion is done, what kind of flexibility do shippers have to move beyond from Oakford into the Northeast market? Do things get stocked up at Oakford and Delmont?

No. In fact, I think you see with TIME III, you can go out of OakFord, pull it out of storage there if you will and then come down into Transco or Texas Eastern. So I think there's a fair number of interconnection, although it is not infinite. I think the key of those projects, you're building to the incremental demands of customers today as opposed to try to create some perhaps fictional demand that may not be there right now.

You believe that there's flexibility to move those molecules farther east?

Absolutely.

Then in terms of where you guys are on the storage side, both at the utility in Canada and also within the U.S., where are you guys right now in terms of storage capacity in terms of being full? Are you 80% full, 75% full or how does that compare to last year?

Well, it would be substantially higher than last year, but the number depending on whether it is Union or the U.S., it's pushing between 80% and 90% at this point in time, so storage is pretty full.

And that's definitely a change from last year for you guys?

Yes, definitely a lot more gas and storage.

On the NGL side, did you talk about a mark-to-market loss in the quarter?

That's just fuzzy. No, that's really just the consolidation of DPM, the MLP at DCP. They do some hedging because they pay out all their cash in distribution like other MLPs, so they put hedges in place, and that's a proportional share of mark-to-market flows through each quarter. So we just back that out since it is not particularly relevant to the underlying earnings at DCP.

So, that's actually excluded from your earnings at DCP?

No, it's not excluded. It's just to give you better vision on what DCP is actually do. So you had $34million before the mark-to-market, you actually had a mark-to-market pickup. So you take that back out which gives you the $24 million for mark-to-market loss.

Faisel, the loss was about $54 million at the 100% partner level, and that compared to losses in 2008 of $170 million. So, it's a $116 million improvement year-over-year.

On the NGL realization, I think you said about 44% realization to crude prices, is that right?

That's correct.

It seems like that would be a little bit lower than some of the market indicators, which were pointing towards 50%. Just remind us what you're seeing with the different components of NGL demand.

Here's the real issue. Ethane, we're now back at about the peaks we saw in 2008, so that's around 840, 825 in terms of million barrels, and the utilization of the steam crackers is 82, 83%. So we have seen a steady increase in that during the year, but the issue is propane inventories are well above the five-year average. And since the propane is an alternative to ethane which is now below the five-year average in terms of inventories, that puts a cap on ethane pricing. So, we have got to see some more economic growth to actually bring propane supplies so that you can see a bigger move in ethane. Our barrel maybe a little bit different than other folks, but I don't think it's material. So it's moved all over the price. Earlier in the year, I think we were seeing some 70% correlation, and it has been as low as just a little bit under 40%. So with the massive move in oil which as you knew was moving for more than just economic reasons, moving dollar wise, et cetera, I think you see a big change. The NGL market, 90% of it is made up of the chemical industry, the refining industry, and then residential and commercial. Those are all domestic businesses that need to get moving to really see an improvement in NGL pricing. With economic growth, you should see that that start to happen in the last half of the year.

Faisel, we average 48% correlation for the first six months, so as Greg indicated the fact that it was 44% in the second quarter really just is a measure of how quickly oil prices have risen relative to natural gas liquids.

With the massive volatility that we have seen in currency and especially the Canadian dollar, what kind of impact does that have on your decision making process for projects or financing and just managing our general business?

Well, obviously it focuses on borrowing money when we invest in Canada and unfortunately we have two equivalent to Fortune 500 companies in Canada, both Union and Westcoast have long histories and are public debt companies in Canada. So obviously it focuses on borrowing there. I think the other thing is we are partially hedged, substantially hedged thanks to the fact that we do borrow up there. So what you may win or lose from an earnings perspective above the interest line the inverse is true, and the interest line. So I think Pat remind me, but I think for the quarter it was $0.01 impact in terms of FX even though you saw pretty substantial moves.

I think we also have to put in perspective. It's probably true with commodity prices overall that what we have seen going on in the last twelve months is not the norm. I wouldn't expect it to be the norm and while there's no doubt you're always going to see fluctuations in commodity prices. If you believe that the economic downturn of the last year or two has been at least as bad as anything we have seen since World War II, if not since the 30s, then I guess it kind of underlines the type of volatility you would see, but you would not expect it on an ongoing basis. I think that gets lost given it's all happened in twelve months.

Your next question is from Ross Payne with Wells Fargo.

First question is for Canada for the gathering business up there. Is that POP or keep hole or what is that?

That's all fee. There is no commodity. The Canadian processing business developed quite differently than the U.S. one. That is a fee business up there. The only commodity exposure we have there, Ros is that the fractionation plant which is Empress. So that's the movements you see up there in that business, and we thought we would earn about $55 million on the Empress side of the business this year, and frankly we have earned about 35 of that already. So the processing business, and what I am referring to when I say we could spend a billion dollars between 2012, that is a fee-based business.

What are you seeing in terms of laying down rigs similar to what we have seen in the States and will that impact the volumes and therefore I guess the fee-based?

A little bit like in the states. It's all location is everything, right, so we actually see an increase in activity up in the Horn River and the Montney region. And again since their fee-based commitment contracts, it's not dependent just on volumes. They are really for lack of a better word take or pay type contracts up there.

Regardless of volumes?

Yes, correct.

On DCP mid, any idea what volumes did year-over-year?

I believe volumes quarter-to-quarter were down about 8% on actuals, probably 5% year-to-date, but much less impact on margin. Margin was only down about 2%. That's because where we saw volumes come off, it was in our low margin areas as opposed to where we saw volumes doing pretty well in the high margin areas. Again, it's a regional game; places like the Rockies were up 6% or 7%, Mid-Continent and Permian kind of flat. We have a lot of activity down here in the Gulf Coast and South Central, those areas were down. Geography is very important as you know in this business, so no single answer really tells the whole story.

Pat, you've got a lot of availability here. You do have a bond issue coming at the end of the year. What are your thoughts there?

Ross, we're going to watch the market conditions. This is a good time to be in the capital markets with over $2.5 billion of liquidity we don't have to. We have got a little over $600 million of maturities between now and the third and fourth quarters. So we're just going to kind of wait and watch and we can access the market if we want to on kind of an expedient basis.

Your next question comes from Matthew Akman with Macquarie.

Are there any implications for the Maritime and Northeast expansion of the fact that counterpart LG is not really delivering volumes right now?

Matt, we have a long-term 25-year contract there that is reservation charges. So we make a return on enough capital on those reserve charges. So those revenues come in and started in March or April of this year and they will continue for 25 years. The transportation cost is relatively modest versus what they trying to arbitrage on the value of gas at any one point in time, but they're doing some commissioning out there. They are flowing some volumes through there now, Matt. So I think that it bodes well that the pipe is in good shape and expansion has gone well. Also they're obviously looking for the opportunities where they can actually make dollars on the commodity which is not our game, but it is theirs.

The pipeline is going to earn its return regardless?

Yes, sir.

Second question on the storage expansion at [Don] to 5 Bcf that came into service at the end of the quarter, can you confirm that that's going to be sold all at market rates under the OEB decision.

Yes, just to be clear, that's actually MHP, so not to confuse the matter too much, but that unregulated subsidiary actually flows through U.S. Transmission, so that is a market based project, and it's actually being completed or put in service by U.S. Transmission.

Is there any more expansion there because that's obviously very low cost expansion relative to other storage around the country and if you do it at market-based rates, it is probably very nice returns.

Yes, we think so. As you know we put some stuff a little bit further up the Bruce Peninsula as well. So we see opportunities there. It's not like 10 Bcf and 20 Bcf. It's probably more like 4 Bcf and 5 Bcf here an there, but we're always looking for those opportunities and as you well know our infrastructure there is so well connected to virtually all those opportunities, we can probably make those assets hum better than some other folks. So we're always looking for opportunities to develop it or if it is attractive to actually go out and acquire some assets. You can do that relatively small discrete acquisitions and bring it into the overall Don system.

On the detailed question, the T-South open season the West Coast system, is that just filling up existing capacity or is there any potential at some point to expand that? Is that on the horizon at all?

That's existing capacity. There is no capital associated with that. I think as you know how the overall volumes flow, whether they go north or whether they first go East and down, I don't see any big expansion of T-South at this point in time.

The TransCanada has announced that it's partnering with Exxon on the Alaska highway gas pipeline and once upon a time Spectra or its predecessors were involved in that project. I am wondering whether you guys have your eye on any involvement in that project at all under some of the new structure that may come out from TransCanada and Exxon?

We're always interested in opportunities. I think the first and pretty substantial capital opportunity is the Horn River, and you know how much capital we're putting toward there, and obviously I think the economics of gas there are better than they are at the further north you go. That being said, look, if that project gets built over time, and that will be a decision obviously of Exxon at some point in time down the road and other producers, that's going to be the largest infrastructure project in the world as I understand it. I don't think any one player may want to take on all of that risk and there will be opportunity perhaps for some others to participate, but I think it is a little early to look at that and that's still well into the next decade before that project really gets humming.

You do have a follow-up question from Carl Kirst with BMO Capital.

Greg, you just touched on the follow-up I had with Don and market hub partners. It wasn't too long ago that you could throw a rock in Houston and hit private equity developing salt dome storage, and since then the markets changed a little bit. The question is are there any sort of half developed projects that either look attractive or are floating around or present acquisition opportunities for you guys

Storage is finicky. You got to make sure you got the right geology and you are in the right location. I know there are a lot of folks that thought it was pretty easy as you suggested to throw a little private equity around and get projects developed. I don't think all of those storage projects are created equal. We're pretty picky about what we look at. That being said, I can't really comment on where we are on acquisitions, but definitely storage opportunities would be something we would look at. If they were supportive of both our current supply region storage that exists and obviously the market-based region and we thought we could do better with pulling those assets than some others. Steckman's a good example of that. We picked up Steckman Ridge I guess probably two years ago or so. That project has been a couple of hundred million dollars, great partner in New Jersey Resources, very well connected into Texas Eastern and other pipes, and that seems to fit the right type of storage project that we would be interested in if we could find one at a decent price.

It's kind of challenging when you only own 50% of it, but do we have any gross margin breakout for DCP yet? Is any of that data available?

Not yet. It will be on their website in the next few days after DP, because, Carl, it has pretty clear insight into what DPM did for the quarter. We don't put it out until they do their call. I think that's probably a little bit later this week. Operator (Operator Instructions). You do have a follow-up question from Anthony Crowdell with Jefferies.

Just two quick follow-ups. One is on the U.S. Transmission business. Could you provide any color to the lower equity earnings, any segment that's from? The second question follows my interest question earlier. Looking at roughly like a $0.07 per share savings from interest expense. Is it wrong for me to assume that the original $1.15 you put out did not include that?

That's correct. There is no $1.15 that we put out, it's just $680 million of interest expense and a lower number of shares. We actually have $646 million weighted average shares outstanding that you could use, but that sounds about right. With respect to U.S. Transmission, we had a couple of things going on there. One, the reduction was about $16 million in total of lower equity earnings from our joint ventures. In one case, about $7 million of debt relates to Southeast Supply Header Project where for technical reasons, we discontinued regulatory accounting under FAS 71 effective I think about August of last year. So, we had a retroactive adjustment that we made. The second piece of that, about $9 million relates to lower interruptible transportation revenues on our Gulfstream project, which by the way is fully contracted, but we sell interruptible service on top of our firm service.

Anthony, the other thing I would add with the interest expense question, I don't think your math is wrong. Take the interest expense, add the tax and then divide by the number of shares, you can get that number, but just thinking ahead of ourselves. That's actually offsetting some of the commodity impacts that we have seen as well. So you take all that into account.

It should caveat that it is also dependent on FX rates with the Canadian dollar staying about where they are for the balance of the year.

At this time there are no further questions. Sir, are there any closing remarks?

Yes. I will just thank everyone for joining us today. Appreciate you being on the call and I do want to remind you that on Thursday, August 13, we're going to be in Boston for breakfast, and then in New York for lunch. You should have received an invitation to join Greg and Pat at both of those locations, and join us for one of those discussions If you haven't already done so, we would appreciate knowing whether or not you're going to be able to attend. We'll look forward to seeing you in Boston or New York, and as always, if you have any additional questions, please feel free to call either me or Patti Fitzpatrick. Thank you.

This concludes today's conference. You may now disconnect.