Sea Limited (SE) Q4 2011 Earnings Report, Transcript and Summary

Good morning. My name is Wade, and I will be your conference operator today. At this time, I would like to welcome everyone to the Spectra Energy Earnings Conference Call. [Operator Instructions] Please note that today's call is being recorded. Thank you. Mr. John Arensdorf, you may begin your conference.

Thanks, Wade. Good morning, everyone. I'm John Arensdorf, Chief Communications Officer for Spectra Energy, and I'd like to thank you for joining us today. We were with many of you recently in New York, providing an overview of our 2012 business and financial plans, and we're pleased to share with you today our 2011 fourth quarter and year-end results. Leading our discussion today will be Greg Ebel, our President and CEO; and Pat Reddy, our Chief Financial Officer. Since we had an in-depth discussion with you just a few weeks ago, we're going to move quickly through our presentation, allowing plenty of time for your questions. Greg will kick things off with an overview of 2011, then Pat will provide a more detailed look at our financial performance for the quarter and year. And Greg will return to wrap things up and provide his perspective on 2012 and beyond. As you know, some of what we'll discuss today concerning future company performance will be forward-looking information within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements, and you should refer to the additional information contained in Spectra Energy's Form 10-K and other filings made with the SEC concerning factors that could cause these results to differ from those contemplated in today's discussion. In addition, today's discussion will include certain non-GAAP financial measures as defined under SEC Regulation G. A reconciliation of those measures to the most directly comparable GAAP measures is available at the end of the package of information you have before you and on our website at spectraenergy.com. With that, let me now turn things over to Greg.

Thanks, John. And good morning, everyone, and thanks for joining us today. As you know, we released today our full year results for 2011, a year in which we continued our track record of delivering on our commitments to you and realized net income in doing so. With respect to the fourth quarter, I'm aware that the outcome was lower than some of you had estimated, and while Pat will take you through the details, I thought it'd be worthwhile to speak to some of the unusual items and unique timing of some of those items as context for the quarter. In the quarter, we booked a number of items that reduced income. They were associated with , one, software amortization; two, employee benefits; three, acquisition-related settlements; four, captive insurance claims; and five, some tax adjustments. In total, these items weighed on earnings by about $0.03 a share. Added to these were NGL curtailments and plant reliability challenges that lowered DCPs earnings by about $0.01 this year. And then finally, with the warm start to the winter, we were able to do more plant maintenance work at U.S. Transmission and Union Gas, which increased O&M costs at those business units. Together, these items resulted in a reduction of $0.04 to $0.05 per share, and represented an accumulation of relatively small items that either would not typically cluster in a single quarter or, as in the case of NGL curtailments, are short lived, thanks to DCP's current investment in NGL pipelines and plant capacity. To the extent that any of these items may occur again in 2012, they've been taken into account in our guidance to you. So turning back now to the bigger picture and the overall year, as I mentioned, we finished the year with record net income. We indicated that we expected to exceed our ongoing EPS target of $1.65 for the year, and we did, delivering earnings per share of $1.77. In support of that achievement, each of our business segments delivered nice EBIT increases for the year. We're benefiting from changing market fundamentals that support our growing Gas Transmission business and our Gas Processing and Distribution business throughout North America. As we look back on the year, we saw a healthy pickup at DCP from favorable NGL pricing. But as a result of the curtailments I've previously mentioned and the effects of winter storms that you'll recall early in 2011, as well as plant reliability challenges, we didn't realize all of that pickup. Fortunately, the new infrastructure being built at DCP, such as Southern Hills and Sand Hills, will ensure that we do unlock our growing NGL volumes and reach premium pricing markets such as Mont Belvieu. Despite that Q4 curtailment issues I mentioned, DCP's year-end NGL production volumes were 6% above fourth quarter 2010 levels. During the year, U.S. Transmission grew its ongoing EBIT by approximately 5%, as it realized earnings from new projects brought into service. U.S. Transmission continues on a stable track. While we have growth in both 2012 and 2013 EBIT in this business unit, we expect the next significant growth in its EBIT to occur when we realize the full year benefits of our New Jersey - New York project in 2014. In Western Canada, in spite of higher extraction premiums, our Empress NGL business experienced strong sales volumes relative to our initial expectations. We've provided a healthy boost to Western Canadian Transmission & Processing. And despite a warm start to the 2011, 2012 winter and a sluggish Ontario economy, our gas utility, Union Gas, grew its EBIT by almost 4%. The point of all of this is the power of Spectra Energy's entire portfolio allows us to perform consistently, growing earnings and the dividend, even in the face of various market cycles and operational scenarios. Turning to the dividend, during 2011, we increased it by about 8% and we have the confidence in our growth plans to commit to delivering annual dividend growth of at least $0.08 per year on an ongoing basis. We invested more than $1 billion in capital expansion during the year and placed 6 projects in the service. Successful execution of our CapEx plan allows us to continue to achieve aggregate returns on capital employed, in excess of our targeted 10% to 12%. In addition to the organic growth and expansions, we executed on 2 strategic acquisitions during the year. We acquired the Big Sandy Pipeline in Eastern Kentucky to our MLP Spectra Energy Partners and DCP Midstream acquired Southern Hills Pipeline, targeting new NGL transportation capacity from the mid-Continent to the premium Gulf Coast market. Our share of DCP cash distributions was about $400 million in 2011, exceeding our initial expectations by almost $50 million, and we expect distributions to continue increasing as DCP grows its earnings. In fact, for 2012, we should receive distributions from DCP of $460 million, 15% higher than in 2011. And we committed to look forward positioning ourselves strategically, leveraging our enviable asset position and seeking accretive capital investment such as recently announced TEAM 2014, open and next opportunities. Overall, we continue to have a balanced approach to serving our investors through both earnings and dividend growth, and we have the flexibility to toggle between the 2 to ensure consistent level of total shareholder return through all market cycles. With that, I'll turn things over to Pat to provide detail for the quarter.

Well, thank you, Greg. And good morning, everyone. It's a pleasure to be with you today to report on our fourth quarter results and overall 2011 performance. As you've seen in our earnings release, Spectra Energy announced ongoing fourth quarter earnings of $287 million or $0.44 per diluted share. For the year, we delivered record ongoing earnings of about $1.16 billion or $1.77 per share. The annual results reflect solid performance from all of our businesses. In particular, we benefited from expansion projects placed into service, higher commodity prices at DCP and a stronger Canadian dollar. Let's take a look now at EBITDA. For the year, EBITDA increased by almost 9%, from about $3 billion in 2010 to more than $3.3 billion in 2011. And as you may recall from our Analyst Day last month, our 2012 EBITDA is budgeted at $3.5 billion, up another 6%. So strong earnings and cash generation from our mix of businesses allows us to fund our sizable CapEx program with no need to issue equity, while maintaining a solid BBB balance sheet. Now we'll take a look at our performance by business segment, beginning with U.S. Transmission, which reported ongoing fourth quarter EBIT of $226 million, compared with $237 million in 2010. The 2011 quarter reflects higher operating costs and as expected, lower revenues at Ozark Gas Transmission. These results were partially offset by incremental earnings from our expansion projects. For the full year, ongoing EBIT for U.S. Transmission increased nearly 5% from $938 million in 2010 to $983 million in 2011. Now let's turn to Distribution, which reported ongoing fourth quarter EBIT of $120 million, compared with $127 million in the fourth quarter of 2010. This decrease is primarily due to lower customer usage related to weather that was nearly 15% warmer than the prior year. Year-end ongoing EBIT for Distribution increased almost 4% from $409 million in 2010 to $425 million in 2011. Let's focus now on results that are Western Canada Transmission & Processing business, which reported ongoing fourth quarter 2011 EBIT of $137 million, compared with $131 million in the fourth quarter 2010. This segment benefited from improved results in the gathering and processing business, driven primarily by higher earnings from expansions in the Horn River area of British Columbia. These results were partially offset by lower earnings at the Empress NGL business, attributable mainly to significantly higher cost of NGL extraction, net of higher sales prices. Year-end ongoing EBIT for Western Canada Transmission & Processing was $510 million, compared with $409 million in 2010, representing an increase of nearly 25%. Now let me turn to our Field Services business, which, as you know, represents Spectra Energy's 50% interest in DCP Midstream. Field Services reported fourth quarter EBIT of $96 million, compared with $108 million in the fourth quarter of 2010. The 2011 quarter results reflect the effects of plant higher operating costs, short-term reliability issues and NGL curtailments, primarily occurring in the Permian Basin. We also recorded lower gains associated with the sale of common units by DPM. These results more than offset the benefit seen from increased NGL prices and volume growth, compared with the fourth quarter of 2010. As Greg told you, the curtailment issues encountered last year further underscore the critical need for DCP's Sand Hills Pipeline, which will play a key role in opening up the flow of NGLs to premium Gulf Coast markets, particularly from processing plants located in the Permian. On average, NGL prices were $0.14 per gallon higher this quarter, compared with 2010. NYMEX natural gas averaged $0.25 lower in 2011 and crude oil was $9 higher per barrel. Year-end ongoing EBIT for Field Services was $449 million, compared with $335 million in 2010, representing a 34% increase. And as previously mentioned, DCP Midstream paid distributions to us of $395 million for the year, exceeding our target of $350 million. Now let me turn to Other, which is primarily comprised of our corporate governance costs and captive insurance and some additional items. Other reported net costs of $28 million in the fourth quarter of 2011, compared with ongoing net cost of $16 million in 2010. The unfavorable variance reflects higher captive insurance cost from miscellaneous loss events and other corporate expenses. Year-end net cost for Other were $104 million, compared with $62 million in 2010. Higher self-insured insurance losses, benefit costs and similar corporate expenses account for the variance. Our ongoing annual run rate for corporate other costs should be in the neighborhood of $100 million, and is reflected at that level in our 2012 earnings guidance. Additional items affecting net income include: Interest expense for the quarter of $154 million, which was unchanged from the fourth quarter of 2010 and fourth quarter 2011 ongoing income tax expense from continuing operations of $115 million compared to the $128 million in 2010. As of December 31, 2011, our debt to total capitalization ratio stood at 56%. Going forward, we expect to fund our CapEx program through a combination of internally generated funds and debt while maintaining strong investment grade coverage ratios. As of December 31, we had total capacity under our credit facilities of $2.9 billion and available liquidity of about $1.9 billion. In other words, more than adequate to supplement our internally generated cash. So that's an overview of our fourth quarter results, now let's take a look at how we reconcile our 2011 actual performance to our 2012 plan. As we look forward to 2012, let's begin with the actual 2011 ongoing net income of about $1.16 billion, which supports our $1.77 earnings per share, and compare that to our 2012 projected net income of about $1.24 billion or $1.90 per share. You can see that the ongoing successful execution of our expansion program will be the largest single contributor to earnings growth with $125 million of incremental EBIT expected in 2012. The split on each earnings will be about 60% from Western Canada and 40% from our U.S. Transmission operations. We also expect a significant contribution from DCP Midstream's expansion efforts and slightly higher commodity prices. As we've mentioned previously, we continue to see volume declines in the conventional areas of British Columbia, as a result of low gas prices. With lower contracted volumes in these areas, Western Canada is expecting a negative $65 million earnings effect in 2012. Also as expected, storage margins continue to be soft, resulting in a storage EBIT reduction of about $30 million, with about 3/4 of that coming from U.S. Transmission and 1/4 from Distribution. Our plan calls for slightly higher interest expense, primarily as a result of higher debt balances associated with funding our growth CapEx. And, of course, the $30 million tax effect is a result of the earnings change as shown here. One supplemental piece of information I'd like to add to the 2012 data we shared with you a few weeks ago in New York has to do with the Distribution of our quarterly earnings. As you know, while we don't provide specific quarterly guidance, I can tell you that all of our projected 2012 earnings growth is reflected in the second half of the year. We don't expect the first and second quarters of 2012 to look materially different from 2011, with the first quarter slightly higher and second quarter slightly lower, assuming, of course, that all of our forecast assumptions are realized. Now let me turn things back over to Greg, who'll speak to 2012 and our active commitment to delivering strong and sustained earnings growth well beyond this year.

Well, thanks, Pat. And just to recap, 2011 was one of the strongest years in our history, with record net income and we'd continue to benefit from the strong macro environment that supports our growing gas transmission business and is accelerating the growth of our gas processing business activities throughout North America. In early '07, we told you we'd grow earnings by investing about $1 billion per year in fee-based businesses and attractive returns on capital in the 10% to 12% range. As you can see here, we're not only meeting that commitment, but we're here [ph]. We intend to continue that growth focus, and going forward, we see opportunities to profitably invest about $15 billion through the end of the decade. That investment will allow us to realize significant incremental earnings and cash growth, with robust returns in capital in that 10% to 12% range. And you can expect an additional $6 billion capital investment kicker from DCP, where returns will average in the mid to high teens. That's an impressive record of execution and, frankly, a menu of opportunity. The power of our portfolio is driven by a number of integrated elements: First, our expansive asset footprint, featuring our first and last mile competitive advantage; our considerable financial strength and flexibility; multiple financing vehicles, be that C-Corps or MLPs or the partnerships that we belong to; our proven track record of delivering attractive returns on capital employed; and finally, reliable earnings and ongoing dividend growth. Our confidence in our ability to continue being the investment opportunity of choice is grounded in the 125% total shareholder return that we provided investors over the last 3 years. We know how to create value and improvement. So with that, we'll turn things back over to John, and we'll open it up to take your questions.

Okay, Wade would you please give instructions on how folks could ask the question to which to do so?

[Operator Instructions] And your first question comes from the line of Ted Durbin.

My first question's really on Field Services. I just -- maybe I missed something, but you had volumes were up 6%, your price is up 13%, yet earnings were down or EBIT was down 11%. I'm just -- it sounds like a lot of OpEx. So maybe you could just give us a little more color there on kind of what happened in the quarter?

Ted, we talked a little bit about some of the plant efficiencies and curtailments that were ongoing in the quarter. And so in the Permian, we had a decrease at the 100% level of about $6.5 million in the fourth quarter. Year-to-date, the curtailments were $42 million, and about $35 million of that's in the Permian. So, again, those were 100% numbers, but that is a pretty significant factor for us. And then some of the plant reliability issues that Greg talked about that are being addressed, as well as the construction that's taking place of our 2 NGL pipelines, one of which, Sand Hills will be in partial service by the middle of this year to take Eagle Ford volumes.

Okay. So -- but if the Permian is -- it sounds like it's more of the issue of that, that is not likely to be until, I guess, at 2013.

That's right.

Yes, and what I'm getting at is, I mean, your guidance for '12 does have a pretty big step-up in volumes out of Field Services, and I'm just trying to make sure that we're not going to run into curtailment issues for the rest of this year, kind of how are you thinking about that?

Well, what Tom and the -- it's Greg, Ted. So what Tom and the team has done is put in some temporary fixes in terms of an ability to get some of those curtailment issues handled, whether it's trucking out some of that product. And then remember, part of the Sand Hills project comes in towards the end of the year in 2012 as well, so that's going to help benefit. And then, there's a bunch of work that's been done on the plant that's going to help on that front too. So we did take into account in our 2012 guidance, making sure that we understood the kind of curtailment issues that could possibly be out there and where we could not mitigate those, made sure they were in the guidance. So we feel pretty good about that at this point in time, that's for sure.

And you may recall that we don't budget for weather, so in the first quarter of last year we had volume degradation from some pretty significant well freeze-ups, and we've added back almost $30 million of EBIT this year for that, price up moderately, expansion volume's up more than $30 million of EBIT, and then added back some volumes or degradation this year that we don't expect to incur again because of plant reliability. And slightly lower curtailments that we're experiencing early in the year. So again, I think we feel good about DCP's contribution to our uptick this year.

Okay, that's helpful. And then I guess just sticking with the NGL theme here. What were the -- maybe I missed this, what were the Empress' earnings for the quarter, for the fourth quarter and then versus what was the fourth quarter of last year? And then I think just you got -- I think you've $100 million baked in for guidance for 2012, what are you expecting there on -- you mentioned that the extraction premiums are higher, are you expecting those to be kind of be flattish year-over-year, or are you going to be paying higher premiums?

So in the fourth quarter of 2011, Empress' EBIT was about $25 million, compared to about $35 million in fourth quarter a year ago, so that $10 million lower. But for the year-to-date, the EBIT in '11 was almost $110 million versus not quite $90 million in the fourth -- excuse me, $110 million in '11 versus year-to-date in '10 of a little under $90 million, so almost $20 million higher year-over-year. We've got $100 million, as you've said, outlooked in our $1.90 for Empress for this year, but continuing to see pressure on net margins as a result of the higher extraction premiums. I'd like to say they've leveled off, but we're continuing to see a little bit of pressure there. So cautiously optimistic about that $100 million for the year, at this early point in '12.

The other thing, Ted, is if you noticed the fourth quarter -- over fourth quarter sales volume out of Empress are higher. So they were -- they're about 20% higher. So they'll continue to do that, that's the benefit of having that storage there. So you're right, we still have extraction premiums very high up there, but our guys go and get a disproportional amount of a volume relative to the size of a plant and that's what they'll do again in 2012.

And your next question comes from the line of Faisel Khan.

I wondered if you guys could tell me if you guys had any impact from this Conway to Mont Belvieu spread at DCP Midstream?

Have we seen any impacts from that?

Yes, to your results or to your earnings?

No, part of the reason why we're building the Sand Hills and Southern Hills is so that we can actually go out there and get that. I mean most of our -- that hasn't been a big move at this point in time, but we don't have the benefit that some other folks do of actually getting all of our product down to Mont Belvieu, so that hasn't been an issue. So you build those pipes, we expect we'll be able to get some of that pickup. And you're right, I mean as -- I think what you're pointing to is you've seen a decline in that spread between the 2 places. But that's something you'd expect as you build in the new pipelines, and -- but you're still going to be better off than what we currently get, where most of our product is stuck up in Conway.

Okay, got you. And then, Greg, I'm wondering if you could talk a little bit about -- right now we're at a very low natural gas pricing environment, could get worse going into the summer. How does that impact kind of your customers on the producer side of the equation? I mean do you think you have counterparty risk on that front, if these guys have experience in low natural gas price realizations. You, do you worry some of that growth slowing down because of the low-price environment?

Well, I think it's more of the -- I mean from a credit perspective, we're well over 80% of our guidance, we're a strong investment grade credits. In fact 85%, so that doesn't worry me. And most of our customers are large LDCs, as well, so those guys are rock solid. If I think about some of the new projects, like we announced, TEAM 2014, the 2 anchor shippers that we signed up there are both very solid players as well. So I don't see it -- if that was sustained over a very long period of time, obviously that would be a little bit more concerning. But then you see, Faisel, the big folks coming in and picking up these assets, right? I mean you're looking at Exelon coming in and I think during its earnings call earlier this week, it may declare plans to continue to drill out its program. And that's got us focused on the short term. So I don't see that as a big negative in the medium term, that's for sure. Low gas prices lead to much stronger demand, and that tends to fix itself there more than driving up the prices. So I think we're pretty careful from a credit perspective. We continue to be able to bring in projects like 2014. So I feel very good about the plans that we have in-date, the projects in execution to-date are going to work through any downtick here in natural gas prices in the short term. What we often forget, as an industry, that weather is a huge factor here and what I can tell you is if you turn to the DCP business, it's really not about $2 or $3 or $4 gas, it's about the liquids, and the places where we are in the Permian, the Eagle Ford, et cetera, those places are going to get drilled out at $2, $3, $4 gas because you're really going after liquids.

So when I'm looking at your kind of macro sort of outlook for the Western Canada, obviously some of that's coming -- a lot of that production's coming from shale gas and pipe gas, and some of that's been driven by, to some degree, by what you think could happen with LNG, but have you seen any slowdown yet in that basin yet because of the low prices?

Well, Faisel, we saw this coming. We saw some of the pullback on the conventional stuff in the Horn River, which, as you know, is kind of bone dry and you've seen the new developments move south into the Montney, where we're active and building our plants as well. So I guess the bottom line is that while we've seen a pullback from conventional, we've seen more than that decline outstripped by the new plays they're coming in. So -- excuse me. I haven't -- I guess the bottom line is we continued to see the growth far outstripping in decline, where people have laid rates down on the conventional side. And you're right, LNG is an opportunity out there as well. I don't know if you saw, but CNPC, I think, picked up a big piece of Shell's Montney play, today, that was announced. And so that's obviously a big player in a big element with respect to building out LNG on the West Coast of Canada.

Your next question comes from the line of Carl Kirst.

Actually, the first question might just be a confirmation. I think I heard Pat already mentioned this, but this is with respect to DCP, the curtailments the reliability issues cited. Pat, you mentioned 6.5, is that the NGL production that was impacted? Where if that wasn't, my question is, is had we not had those curtailments, what would production have otherwise looked like?

Yes, that reference that I made really is to NGL curtailments, Carl. And that was, again, primarily in the Permian, that was about $6.5 million in the quarter and about $42 million for the year-to-date. So that's kind of the magnitude.

Oh, okay. I'm sorry, that's a dollar number, that's not a thousand...

That's not volumetric.

Do you have a volumetric, by any chance?

I don't think we have that handy, we can certainly get it.

I can get that offline with John, no problem. And then one other maybe question on the pipeline side. I didn't know, just to sort of dot the Is, if you could tell us what the impact of Ozark was, that was one. And then just kind of a follow-up to your -- to the timing comments and then also again appreciate the quarterly timing without trying to give too much guidance, but as we look at the shape of pipeline EBIT, typically, we tend to think of something that's more sort of a winter weighted, and here we saw kind of fourth quarter being more of the low of 2011. And as we look at first quarter, first quarter 2011 was quite strong. And so recognizing that you talked a little bit about first quarter, overall, perhaps meeting, maybe slightly beating first quarter of 2011, is that going to be true on the pipeline as well and it's just more to make sure we have kind of a quarterly shape correct of the overall year.

Okay. Well, with respect to your first question, the impact of Ozark in the quarter was about $6 million, and there was some smaller effects on a couple of the other pipelines. All taken together, about $12 million in total.

And then on the second one, maybe as Pat's looking at some numbers, I think with respect to the shape, one thing to remember between 2010 fourth quarter and 2011 fourth quarter, Carl, because you're right. Usually, you see that stuff coming in the fourth quarter a little pop, but remember, we brought in really big projects in 2010, so TEMAX, TIME III. You're talking about $600 million, $700 million worth of projects, of which I think, for 2010, the full year impact of those projects was about a $200 million, where the full year impact of the projects we brought in the U.S. this year would be more like $30 million or $40 million. So you're not -- it's kind of that issue of timing, so we brought in much bigger projects last year so -- and you got 2/10 or 2/12 last year, this year we're bringing in smaller projects and you get 2/12 of a smaller number. So that's the way -- what happened. Now this year, as we're bringing in, as Pat said, you're really going to see the benefit across all the business units in the back half of the year.

Fair enough, that's very helpful. And then with respect, maybe going from the fourth quarter to the first quarter, as we've kind of, I guess, saw around 226 of EBIT here in this fourth quarter, first quarter last year with 275-ish, is that a ramp that can be mimicked or should we be thinking of something more flat through the year, for instance?

Yes. It's more back-end loaded. I didn't look to see much of a change in the first quarter.

And your next question comes from the line of Becca Followill.

Just once again, on Sand Hills and the timing if that. Its partial service is mid-2012 for the Eagle Ford portion. What is the timing to bring on the Permian portion?

So the rest of that'll be kind of mid-2013.

Mid-2013.

Correct.

And no partial ramp-up in that at the beginning of the year?

I don't think so, that's that the plan. I mean there's no doubt that given the value that we leave on the table by not getting to the Gulf Coast market, they'll be doing everything to get there, but that's not the plan as of right now, Becca.

Okay, great. And then the final question is one of your peers talked this week about a major pipeline modernization program, spending $4 billion over the next 5 to 10 years, have you guys started to discuss anything like that with your customers to be able to recover costs or have any plans for some kind of major pipeline program?

Yes, well, we've been doing that for the last 10 years, so we don't see -- that's probably related to the pipeline safety reauthorization act that finished -- that was signed in the law in January. We've been ramping up our program on that front, and I think you can see that in our maintenance capital. Now the regs have to come out on that, but I don't see that having any big material impact. Each one of the pipes is different. We don't -- folks with their steel pipe and big Distribution operations in the U.S., that often creates a much bigger challenge for them than it does the interstate pipe. And no doubt we'll just have to continue spending money out of the maintenance side of things, but I don't see anything like the magnitude that you're talking about.

And your next question comes from the line of Matthew Akman.

Pat, you mentioned $65 million impact in Western Canada from volumes, is that -- I'm sorry I'm not sure if I missed it, but was that Empress or Horn River or did you break that down?

I don't think we broke it down, but it's primarily conventional dates, things like Grizzly Valley. As we move into this year, we're -- with recontracting, we didn't see full volume commitments being subscribed for, so it's primarily or more heavily, Grizzly.

And not Empress, though?

No, not Empress. No, not at all.

Can I move to Union Gas for a second? I'm just wondering if you guys have factored any weather impact into your guidance?

No. We always assume normal weather, Matt.

So, obviously been pretty warm in January. Any update on that or thoughts on what the possible impact there might be?

No, I can't tell you, I haven't seen the numbers for January yet. Obviously, that's a negative issue now, but at the same time, we have offsets to some degree and it uses much compressor fuel and things like that, but we'll just have to see how the quarter plays out.

Okay. In the first place, the recent Distribution was forecast to be down anyhow in '12 versus '11. It was related to primarily what, was that average use or...

Basically 3 factors. You got some storage and you've got FX. Believe it or not, FX is actually lower in 2012 versus what the actual was for 2011. So that's the big pieces that would be in there.

And your next question comes from the line of Craig Shere.

Pat, on Page 11, that bridge, that was very helpful. The $30 million headwind on storage, is that just pure contracting or is that net of annualized contributions from new capacity that's been brought on?

It's really the net effect, of both of those things, Craig. Realizing that storage margins have cut an end, so on, on capacity and storage, it's recontracted. It's at a lower average rate, and then for new capacity, like at Egan or Bobcat, it would be reflecting current rates. And then given that storage rates were a little bit stronger in the first couple of weeks of the year, we looked at keeping a little bit of our capacity that came due a short-term to take advantage of the slightly higher spreads.

Okay. So those expansions you mentioned, those are all coming old in that middle column under storage, not under that first $125 million growth number?

The storage effect is in that 30, that's correct.

Okay. And not beat a dead horse, and it's doing phenomenal, but on Field Services, with the temporary fixes on some of the curtailment issues particularly in the Permian with trucking, we kind of heard on the producer side when they've had to resort more to trucking that you can get some pretty severe basis blow out because of the tightness of not only trucks, but drivers that can do that stuff. Do you feel like whatever temporary fixes that are in are pretty much known quantities in terms of cost?

Well, I would expect so. I think from a cost perspective, I think we've got it. I mean it's not just things like trucking, it's also -- and we are today, reliant on third parties -- third-party pipelines. And so, obviously, those pipelines have to run well for us to do well. We've put a little bit more, though, from a curtailment perspective in our budgets, so we think we've taken in account between taking that into account between doing a better job on plant reliability and some of the mitigation we've put in place, be it trucking or the like. We feel pretty good about -- that we've got things taken into account for 2012.

Your final question comes from the line of Luis Shammy [ph].

So I had a couple of questions. First one was with the planes buying into the Western Canadian Processing assets from BP. Can you talk a little bit about the competitive dynamic up there as regards your share in the Empress plant, and how that works?

Yes. It's a pretty challenging environment. You basically have about 12-day of capacity and you got 5 or 6 in volume flying by the plant. So the issue is you have to go out and, for lack of a better word, bid for your gas, which is what we call the extraction premium. And so despite the fact that you've seen very high liquids prices and oil and very low gas, which would naturally give you a very nice frac, most of that gets beat up by having the extraction premium. And so the guys up there have a task of going up there and getting more and more volume, and that's what they've been able to do. They did that in 2011, I expect they'd do it in '12. As to what the actual purchases by planes does and others, Providence sold their pieces well. That could lead to some rationalization up there, which arguably, I would suggest that's good for the marketplace, but right now, it's pretty competitive.

Got it. And as regards the U.S. Transmission segment, can you talk a little bit about what the impact was in Q4 from, and projects coming online? I think -- didn't the TEMAX project come online this quarter?

Well, actually, I think that's what I was trying to explain to Carl. When you look at Q4, you're right, some of the final construction finished on TEMAX in the fourth quarter or this year. But we, actually, the way that was contract construction, we've basically brought all that revenue in, in 2010, so you didn't see a tick-up there. So what you saw in the fourth quarter of this year was of an $11 million pickup, with respect to expansion projects that were brought in either last year and we got the benefit this year, or throughout 2011. So it's about -- $10 million, $11 million would have been the actual number. But you're right, when you think about TEMAX coming in, you might have thought there was a big bump there, but, really, we got the big bump last year.

Okay. That makes a lot of sense.

There are no further questions in queue at this time.

All right. If there are no further questions, I'd like to thank everyone for joining us today. And as always, if you should have additional questions after the call, please feel free to give either Roni Cappadonna or me a call. With that, we'll -- thank you very much for calling in.

That does conclude today's conference call. You may disconnect at this time.