Good day, ladies and gentlemen, and welcome to the Targa Resources Fourth Quarter 2014 Earnings Conference Call. [Operator Instructions] As a reminder, today's conference is being recorded. I'd now like to turn the call over to your host for today, Ms. Jennifer Kneale, Director of Finance. Ma'am, you may begin.

Thank you, Ben. I'd like to welcome everyone to our fourth quarter and full year 2014 investor call for both Targa Resources Corp. and Targa Resources Partners LP. Before we get started, I would like to mention that Targa Resources Corp., TRC, or the company; and Targa Resources Partners LP, Targa Resources Partners, or the partnership, have published their joint earnings release, which is available on our website, www.targaresources.com. We will also be posting an updated investor presentation to the website later today. I would like to remind you that any statements made during this call that might include the companies' or the partnership's expectations or projections should be considered forward-looking statements and are covered by the Safe Harbor provision of the Securities Acts of 1933 and 1934. Please note that actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings, including the partnership's annual report on Form 10-K for the year ended December 31, 2013, and quarterly reports on Form 10-Q. Speaking on the call today will be Joe Bob Perkins; Chief Executive Officer; and Matt Meloy, Chief Financial Officer. Joe Bob will start off with a high-level review of performance and highlights. He will then turn it over to Matt to review the partnership's consolidated financial results, its segment results and other financial matters. Matt will also review key financial matters related to Targa Resources Corp. Following Matt's comments, Joe Bob will provide some concluding remarks, and then we will take your questions. There are also several other members of the management team available who may assist in the Q&A session. With that, I will turn the call over to Joe Bob Perkins.

Thanks, Jen. Good morning, and thanks to everyone for participating. Before we turn to Targa's results, I'd like to provide you with a brief update on the status of our transaction with Atlas. The remaining step in closing the transaction from our side is the Targa Resources Corp. shareholder vote, which is scheduled for February 20. As you probably know, all 3 shareholder advisory services: Glass, Lewis; ISS; and Egan-Jones, all recommended that their clients vote their approval of the merger, recommending the vote for TRGP to issue shares in connection with the merger, and we fully expect the transaction to close on February 28. We are coordinating closely with Atlas management who will soon be Targa employees as we head toward close. And the more we interact, the more we realize that the fit of the businesses and the fit of the people are extraordinary. Since we announced the Atlas transaction in October 2014, commodity prices have moved downward, but the Targa and Atlas pro forma combination is better positioned than either partnership stand-alone. Targa is adding scale and diversity with very well-positioned assets and very good people. And our well-received access to the capital markets since the beginning of the year illustrates our financial strength even in challenging commodity markets. Under any reasonable forward price forecast, the merger with Atlas is a great combination, and we are excited to be close to finally getting the deal closed. Let's now discuss Targa's performance highlights during the fourth quarter and across 2014, plus some color around current market conditions. As you saw from our press release, we are pleased to announce that 2014 was a record year for Targa on multiple fronts: record adjusted EBITDA of $970 million, an increase of 53% over 2013, very strong performance given 2013 was…

Thanks, Joe Bob. I'd like to add my welcome and thank everyone for joining our call today. Joe Bob discussed some full year 2014 records, highlights and context for 2015, so now let's turn our attention to Q4 results. Adjusted EBITDA for the quarter was a record $258 million compared to $216 million for the same period last year. The increase was primarily driven by a 26% increase in operating margin from our Logistics and Marketing division, resulting from increased LPG export and fractionation activities. Our Field Gathering and Processing margin increased by 5% driven by contributions from the Longhorn plant that commenced operations in May 2014 and the High Plains plant that commenced operations in June 2014, plus higher natural gas prices, offset by significantly lower NGL and condensate prices. Overall, operating margin increased 12% for the fourth quarter compared to last year, and I will review the drivers of this performance in our segment review. As we have mentioned before, please note that we benefit from the receipt of certain minimum contract payments at year-end that we do not otherwise see in the first 3 quarters of the year. In Q4, approximately $10 million of our operating margin was from the receipt of take-or-pay reservation fee deficiency or other such contract payments. Net maintenance capital expenditures were $21 million in the fourth quarter of 2014 compared to $18 million in 2013, bringing full year 2014 maintenance CapEx to $71 million. Turning to the segment level. I'll summarize the fourth quarter performance on a year-over-year basis, starting with our downstream business. Operating margin in our Logistics Asset segment increased 17% in the fourth quarter of 2014 compared to the fourth quarter of 2013 due primarily to higher export and fractionation volumes partially offset by increased operating expenses associated with…

Thanks, Matt. I'll try to make up for my not-so-brief introduction with a fairly brief conclusion covering some additional thoughts for 2015. In January, we published stand-alone Targa preliminary growth CapEx of $490 million, to $675 million, as Matt mentioned. While the reduction in commodity prices and producer activity is causing us to revisit the optimal sizes and timing of our previously approved and announced new Delaware Basin and Williston Basin plants, and may reduce or slow some of our other capital investment activity on the Gathering and Processing side, on the other hand, this price environment may lead to additional opportunities for a well-positioned Targa. For example, we have modified the existing agreements we had in place with Noble to construct a condensate splitter at our Channelview Terminal. After a brief period of study, Noble and Targa will move forward with either a new Patriot Terminal with significant storage capacity, a splitter at Channelview or perhaps both projects. For structuring some additional optionality into our agreements with Noble, Targa benefited from the receipt of a first quarter payment in 2015 and will receive enhanced economic benefit over the life of the project or projects without taking on any additional risk. Additionally, the contango in commodity prices has already led to significant inbound interest from customers interested in discussing projects with our petroleum logistics team. On the downstream side of our businesses, we are proceeding with the construction of our fifth fractionator at Mont Belvieu. We call it Train 5, and we will submit a permit for Train 6 very soon. We continue to pursue an ethane export project and remain cautiously optimistic. Interest is being driven from a diverse set of potential customers, including pet chems and other end users. While the recent price shock creates some uncertainty and…

[Operator Instructions] Our first question comes from the line of Jeff Birnbaum of Wunderlich.

So I appreciate the additional color on the call this morning, and I understand kind of obviously some of the conflicting demands that you're given, kind of the desire for more color in a very uncertain environment, but I just want to ask, am I kind of hearing you correctly that kind of in your view in this kind of price environment, maybe we can make our own assumptions perhaps price risk and volume risk given your December guidance -- relative to that, I should say, but that you think that perhaps given a little more updated or optimistic outlook for LPG exports kind of can sort of make up the difference in your view here in terms of your '15 distribution and EBITDA guidance?

Jeff, you covered a few things there. I think you're directionally correct in that, yes, we have lower prices than our December guidance. I believe that, that guidance spoke towards prices and volumes, and you could extrapolate to other price and volume scenarios like a $50.50 world, pretty easily in terms of what that coverage would look like in that $50.50 world, volume-adjusted. Directionally, you're correct. Our export performance is likely to be better than the volume assumptions included in that lower data point. I am not saying that they will offset because I don't know where the lower prices are. I cannot predict a bottom on commodity prices. We're using a working assumption for managing the company that says that prices on average for 2015 may be modestly better than what we've experienced in 1.5 months to date. And with that working assumption that prices are significantly better, it won't be hard for us to adjust. They're a little bit worse, it won't be hard for us to adjust. But I think you can, with your own modeling, assume that we're not concerned with something like 1.0 or 0.9 coverage for a quarter or for a few quarters because that's not difficult for us. And at very low price levels, if we have an outlook that those price levels are going to improve and that activities are going to improve, that's the right way for us to use our coverage. If we were at today's prices flat and knew they were going to be flat through 2016, we certainly could not deliver on that same previous guidance distribution level. But you can do math in between. Was that helpful?

Okay... yes, no -- that is, Joe Bob. And I guess I just wanted to kind of -- 1 additional question kind of on CapEx here. It sounds like kind of full speed ahead with Train 5 and permitting for Train 6, so I guess the kind of read there, is there any other color you can give, I guess, on -- at least in terms of the CapEx for field G&P, how you -- I think you had mentioned that a little bit, Joe Bob, in your comments, where -- how you could kind of see that evolving in '15 and 2016.

Our mindset is to be very efficient with the capital we're spending on the field G&P side while meeting our producers' needs, and we'll do that combined with the Atlas assets. For example, in the Permian, even better, right? Because we've got an even bigger super system that can respond and have available capacity for whenever the uptick goes without having to have spent as much capital early on, and that's a good thing. Our guidance the first part of this year was trying to describe Targa stand-alone, reducing its capital preprice shock estimate for 2015 to 60% to 80% of those original values. And that's done by downsizing and/or delaying primarily Gathering and Processing CapEx. I know enough about the Atlas planning, details that are appropriate to prior close to say that those same sort of directional indicators on their G&P side are appropriate and we might actually spend even less capital. Put the assets together and we're going to be very smart about it without hurting our returns on the capital and probably just delaying some of the projects to make up for delayed producer activity. On the downstream part of our business, you are correct. Train 5 is full speed ahead and so is the permitting on 6, but in the current price environment, with lower resulting LPGs going to Mont Belvieu, it may delay when we actually build Train 6. But again, it's a question of when, not if on Train 6, and we'll add that capacity when it's appropriate for supply needs. The Channelview project in our downstream, I expect we'll be spending about that same amount of capital that we're stepping back and studying or maybe a little bit more with the same EBITDA expectations -- better EBITDA expectations than we had prior to the end of the year renegotiation. Did that help?

Yes, that's very helpful. The 1 follow-up I'd have is -- and I guess it sounds, to the extent you can give color on it that -- and it seems reasonable that, perhaps, you'd see more or less -- more of a -- less CapEx kind of or infrastructure additions on the G&P side from, call it, non-legacy Targa basins than from legacy Targa basins.

I think it's similar in direction and it will be scaled to producer activity. The Atlas, the non-legacy Targa is the soon-to-be former Atlas assets without going into detail right now, we've got a similar picture. Of course, one of the best areas is going to be West Texas, and one of those I'm going to be slowing down is North Dakota.

Our next question comes from the line of Brad Olsen of TPH.

Joe Bob, you mentioned enhanced cost management as one of the priorities for 2015. I was wondering if you might be able to provide some color on what those cost management strategies might consist of and how much do you think there might be in terms of cost savings and benefits that you could realize in 2015 and beyond.

Thank you, Brad. I think I'll say, yes, I can help on the first part; then, no, I don't intend to in the second part. For example, our operations managers, all Targa operations managers, what we call area managers, were together last week. And I was pretty enthusiastic to hear how they had already begun to implement the 2008, 2009 playbook. That implementation had not just ideas, but actions and active cost savings occurring in the area of -- I can remember from 2008, they said we want to pay 1x, not 1.5x, and what that means is we can reduce our own overtime, which is a much safer thing to do anyhow, and we've been trying to hire by perhaps adding employees. We can't reduce how much time we're spending with contractors who, in the running gun times, are doing work that Targa employees could otherwise do, and believe me, that cost a lot more than 1.5x. We've got a lot of good contractors. I don't mean to be taking it out on them, but that will be the natural occurrence of things just as it was in '08, '09. I'm interested in cash wherever we can get it. Compressors, we're installing our own compressors and having to dislocate compressors we are leasing, that against an even broader portfolio, with Atlas and Targa combined, there are even more opportunities to do that. There are quite a few costs associated at every plant that sort of went up with oil prices. Believe me, we'll be among the most aggressive of pushing it down with oil prices, and that ranges from chemicals to trucking fees, et cetera, that got their own fuel surcharges. I won't pretend that we've got as much leverage as E&P companies do on third-party providers, but you can assume that our playbook looks very similar to them. That's just a short sample. Our guys came in with a slightly scrubbed budgeting. You know how budgeting occurs. It started last fall -- way before the price shock, and they thought it was finished about the time the price shock occurred. They reduced their OpEx budgets to finally be approved by our boards just after the 1st of the year. Our focus was primarily on EBITDA and margin without getting carried away on what we thought the OpEx budgets could be reduced to. Every one of those area managers told me they would come in under their budgets, and I'm certain they will without giving up at all on what is a very sophisticated preventative maintenance program and without giving up one iota on safety because we've done it before, and most of those area managers were here in '08, '09. Now I know you'd like to know the number. I don't intend to disclose that today, but it is a nice compensating factor as we're working in a lower price environment and we know how to execute.

Got it. That's great color, Joe Bob. One follow-up is on the kind of investment multiple side. When we think about processing plants and G&P activity where historically you've sought 5x to 7x type multiple, that obviously -- it comprises, at least partially, a commodity levered percent of proceeds component. And when you look for projects now or when you're thinking about your budget and potentially deferring certain projects, are you having to kind of move those targets to compensate for what very well could be a lower percent of proceeds type fee over the next couple of years in the lower price environment.

My short answer will be no, I don't expect to see the returns to go down. But then I'll give some more color on that. That 5x to 7x and we've often said it, is how we characterize the major announced projects on our capital budget rollout that we present to the markets. You all know that there are a lot of smaller projects on the list and they do considerably better than 5x to 7x when you're leveraging existing infrastructure. So first of all, in a capital efficiency focused world, producers aren't making great, big changes. They're making more incremental changes and we're hooking up smaller acreage dedications and smaller groups of wells. Those returns, I do not expect to be lower than what you just characterized and, frankly, have never been lower than what you just characterized. Capital efficiency is like in Versado, where we've got active projects now because the activity is still sufficient in the Permian Basin to just lay plastic pipe and add a little bit of compression to bring home producers to existing processing plant capacity. I can assure you, we do better than 5x to 7x on that while still providing a very important service to our customers. Similarly, any of the big projects on the board for downstream, their returns aren't suffering. The remaining downsized potentially delayed projects that we focused on a second ago, meaning the Permian Basin plant and the Badlands plant, I don't expect to get lower returns on those capital, though I may spend less capital. Does that help?

Yes, that's great color.

Our next question comes from the line of J.R. Weston of Raymond James.

I just wanted to kind of touch back on LPG exports. You were talking about it a little bit earlier, just kind of thinking about the volatility in commodity prices recently, especially the drop in crude prices, and maybe if that has created any more opportunities for you to move spot butane shipments across your LPG docks.

You are correct. We've had very steady appetite for butane shipments and we've done quite a bit. I expect that interest to continue. If we sort of talk about the moor across our export dock, I can't get much more across our export dock right now. I'm so proud of our people just lining up, managing the logistics, making space for our customers, term customers and short-term customers, exceeding our expectations, as we just reported, relative to effective capacity. And we export butanes, we export -- provide export services for HD-5, provide export services for low ethane propane. I'm just happy we haven't -- with all of the low ethane propane going across the dock, we really didn't have to cannibalize the butane or HD-5, and their interest in getting that capacity continues.

Just kind of switching gears a little bit and just thinking about the fact the U.S. is really going to have a glut of refined products here in the Gulf Coast that they need somewhere to go to. And just maybe your color on how you're looking at additional petroleum logistics opportunities, maybe more middle distillate, residual fuel or distillate export opportunities at Patriot or Galena Park. Patriot maybe has a little better proximity to some producing fields and existing customers, so I was just wondering if you had any thoughts on that.

I agree with your view that there are likely to be additional opportunities from our existing facilities on the East Coast, West Coast. We see that we have not been involved yet in exports, though we have helped move it around the country, so to speak. The Patriot dock project with Noble really disclosed all that I'm comfortable with because of the important work we're doing with that customer, but it is positioned to have a lot to do with refined products, whether by pipeline or shipped with the right dock. That's really about all I would say about it right now.

Our next question comes from the line of Shneur Gershuni of UBS.

Just wanted to do a couple follow-ups to some of the earlier questions. I guess starting with some of the comments that you made about guidance. Maybe I'm paraphrasing a little bit but when you did the $80.80 and then $60.60, when you went down to 60, I'm assuming or paraphrasing rather, that you had sort of made some volume assumptions based on the lower commodity environment. Yet, you kind of still have a mid-single-digits kind of volume growth number. I was wondering if you can sort of give a little bit of detail on how you get there, which basins you're seeing volumes go up, other basins where you're thinking volumes go down. And is that still consistent, given the barrage of E&P companies that have been cutting CapEx? Were you sort of anticipatory of them basically hitting some of those regions and so forth? So I was wondering if you can sort of talk about that volume number a little.

Okay. December 10, I think it was. We attempted to provide our best estimate based on close customer contact to that time, consistent with a $60.60 world, and what we said was low single digit, not mid-single-digit, resulting from our best estimate of that world, pro forma with Atlas, where we weren't as detailed as we were with Targa but where we did share information and perspectives based on their latest conversations with producers. Are we perfect on that? I doubt it, certainly not when you get to per basin, but I still think it's a pretty reasonable assumption. 2015 and remember, that was 2015 relative to fourth quarter 2014. I think it's still a pretty good estimate and we'll be a lot smarter as we actually see what happens. And that had built into it, what are producers are doing in the first half and what did we think they might do in the second half and we'll get a lot smarter about that as well. Now in terms of some directional indicators of how we got to that low single digit, without going into the numbers for each of those basins, it would be a really good assumption to assume that if we rank order them, that the Permian Basin had the best performance in the group, relative to cutbacks by producers, knowing of course there will be less wells drilled. Having some insight to where they might be drilled, that was the best. The area I worry the most about, I mentioned in the previous answer, is North Dakota, who's getting hit both by lower prices and a differential issue. Fortunately for Targa, for 2015, we've got -- I hate to give it a nickname but some backlog volumes. Backlog in that when that plant comes on next week, knock on wood, or I'm going to get really frustrated because I'm already frustrated, it will help several producer customers put out players. The cast is just either flaring or the whole well is shut in because they can't flare anymore, waiting for that plant. We're also waiting for some right of way from the Indian reservation, and that can be a source of frustration, but that's a backlog of volumes. We also have a backlog of crude volumes waiting for some connections currently being trucked that are dedicated to us when we can get there. So that mitigates it a bit, but that's the one that's kind of on my most worried list and we try to be conservative about what we thought that would look like as we put together those December. A lot has changed since December, but as we put together those December numbers. Somewhere in the middle of that would be North Texas and Oklahoma. South Texas, kind of in that same area code. Is that helpful?

Yes, no, that's very helpful. And maybe as I think a follow-up to some of the questions I think Brad had asked, we've sort of -- everybody's been sort of been focused on what are the synergies in terms of cost savings between Atlas and Targa combined and so forth and I recognize we have to wait and see until you get in to be able to fully be able to sort of outline that. But I was sort of thinking along the lines of there are a lot of G&Ps, some of your peers have reported already or sort of indicated a need to do some major cost overhaul and restructurings. Obviously, in your fourth quarter results, we saw some change to your long-term incentive plans. I was wondering if that's something that you're aggressively pursuing now. Is that something we'll see going forward? Do you need to wait for the close of the deal to just sort of execute and so forth? I was wondering if you can sort of give us some color on how you are going to further manage or potentially manage cost. And do you have the same opportunity as some of your peers?

There were several pieces to that question I was trying to get in order of what I wanted to talk about. First, let's start with do we have the same opportunities as some of our peers. I don't know if it's a problem or an opportunity but what we have is 2 very well positioned companies, both of which short of people, okay? Now the good news is we got high talent in both companies, so the priorities were mostly getting covered but we were short of people. Now we may not hire as many as we thought prior to the price shock and we now have the advantage of being able to recruit talent and say, "Do you want to live in Tulsa, or do you want to live in Houston?" And we will look at those open positions very carefully, but this is not a headcount reduction exercise by any stretch of the imagination. It's just the opposite. We think in this downturn, we will add selected talent from those people who were laying off folks, not necessarily their laid-off employees but the employees who don't feel sort of good about to ship their own when they saw other people getting laid off. I really believe that's where we are in my outlook for '15 and '16. If it goes on longer than that, everybody's reassessing. That's a good thing. But the cost savings opportunities are significant. When we announced the deal, we announced it with $20 million to $30 million, right, $20 million to $30 million of synergies. Our Targa philosophy on things like that would be rather to underpromise and overdeliver. Matt will speak up but the ultimate realization just on interest rates associated with redoing the Atlas debt, gets you 1/2 to 2/3 of that.…

Our next question comes from the line of Sunil Sibal of Global Hunter Securities.

A lot of my questions have been addressed already but I had a couple of housekeeping items, first of all. On the noncash incentive plan reduction that you benefited from in the fourth quarter, I was kind of wondering, your SG&A fell about $15 million sequentially. So how much of that $15 million involved that noncash investment expense savings? And then how should we think about SG&A going forward?

First let me answer part of the question that I just forgot from the previous question, and then Matt might be able to give you a way to think about it going forward. We did not restructure our LTIP plans, those LTIP plans remain unchanged. What happened was our equity suddenly was priced much lower, and that flows through the accounting for it, as you know, we have to do. So I didn't want anyone to think we restructured the LTIP plans. I think our LTIP plans are market, provide the long-term incentives that investors want to have for the employees who benefit from that LTIP plan. It is hopefully getting a lot of them thinking like owners and that's how we need to think going through the price cycle as we are. Matt, do you have anything else to add?

No, that's it. I'd say the change that you saw in the fourth quarter was related to the LTIP plans or the delta was related to the price of basically NGLS and TRGP, not a restructuring. And that makes up the lion's share, and that was actually -- there was some offsets going the other way, some increase and some other overhead costs.

Okay, so basically what we can do is see the delta and kind of project it with the prices on the [indiscernible] TRGP and NGLS, I guess?

Yes, I think you could from a modeling perspective.

Yes, well, that's helpful. And then I think you touched upon this quarter, there was a $10 million take or pay kind of makeup fees. Any particular segment that, that is directed towards?

That's both in our Gathering and Processing and in our downstream business. It was not, as Joe Bob mentioned, it was not LPG exports but there was some small amount underneath our take or pay and our fractionation and then some volumetric take or pays on the Gathering and Processing side.

When we say take or pay, we're doing that with kind of term of art. It's a reservation fee.

Or a volume. It's a full family of those.

Yes. On the -- so no one jumps to the wrong conclusion, that's kind of a modest amount of shortage on the Gathering and Processing in those particular contracts which I'm not going to get into. And for the most part, our customers are above their take or pay levels in the fractionation business with some being below. We don't plan for more than that notional 90% take or pay level. And those who didn't get there pay us cash for not doing so, instead of paying us for the volume that made up that 90%. But still, that's should not be viewed as any indication that we're not highly utilized in the fractionation business.

Okay, that was helpful. And then lastly, I was wondering if you could talk a little bit about M&A environment in the current situation and how are you guys thinking about that post closing of the APL acquisition, and any particular type of asset sets which may be more opportunistic for your guys. I think you mentioned about dislocations leading to opportunities, and I was wondering that's probably more organic versus M&A.

Never want to think of M&A instead of organic. We look at M&A also. Though our organic will be done consistent with our customer needs and capital efficiently. My experience in cycles like this is the first things that really pop up tend to be smaller and bolt-ons. And when I talked about opportunities associated with the price dislocation, we're looking for those. Likely to be smaller, very interested in bolt-ons, can take advantage of perhaps someone's need to sell where we can tuck it into our now expanded asset base. Later in the cycle, we know that there'll be some larger things available. Targa's in a good position to look at it, but we'll look at it with the same kind of rigor we always have. And no, I don't have any particular new strategy on what to look at. It sort of starts by making sense with our existing asset base in our wheelhouse of the businesses that we're currently running. And sometimes, we look at larger stuff that has more of that in the package.

Our next question comes from the line of Jerren Holder of Goldman Sachs.

I just have one quick one. We saw another Michigan company mention renegotiating some contracts for Evergreen T&F, terms that were underwater. Any opportunities for you guys when you think about some of the legacy fractionation contracts?

We have some portion of our contracts that haven't been -- that were under long-term contracts that haven't been renegotiated at current prices, but most of our contracts have been renegotiated over the last several years. So I'd say there are some opportunities for that, but the lion's share of our fractionation contracts have been redone relatively recently.

Yes, we don't have much coming to term.

Our next question comes from the line of John Edwards with Crédit Suisse.

I want to come back to your comment about the 2008, 2009 playbook. And so I'm just -- if you can give us a little better idea on the kind, maybe the percentage savings you were able to get in that environment. And I'm assuming from what your other comments, that shows up not so much on the G&A line but actually in the operating expense line is that -- so if you could answer those 2 questions real quick.

Sure. I think I'm going to regret having said the playbook, but the reality is that's what our area manager said. I had as soon as the note went out, but after the end of the first year, he said I already pulled out my notes from 2008, 2009. And another one said, I've got the playbook, I'm sharing it with others. I am so -- I perhaps don't filter enough. I am not prepared to give you a percentage. I understand why you're asking the question. At the time, I was talking primarily where the rubber meets the road for us out in the operations with our area managers on both the G&P side and the downstream side. During running-gunning times, you start paying premiums to keep up with your customer needs and things cost more. We will be saving significant dollars from our suppliers, our vendors, contract labor, our own overtime labor, okay? Products and materials will get meaningfully cheaper. We've already had proposals and some of those proposals we've asked to be reduced on things like chemicals, okay? Oil is the primary component and an excuse for increasing it and it's cut in half, you can imagine that we can get a pretty significant reduction in chemical cost, for example. For engine oil, okay, that's a pretty easy negotiation to get back to, and we use a lot of it. You said how much, and I'm not giving you how much, but the G&A, I kind of talked about. Some of it, we don't have work for, okay? It goes away because Philadelphia and New York go away. We aren't trying to get rid of headcount G&A. The normal public company costs of 2 other companies are kind of a freebie for us. We will be keeping a separate set of financials for some outstanding note holders. That's not hard to do and not very costly. Making it public style to the extent we do for equity is much worse.

Okay, that's helpful. So then the other question, you sort of tapped around the guidance question. So just to confirm, so the mathematical interpolation from your December guidance, that still holds, is that a fair read through on your comments?

Yes, it's hard for me to confirm how people are doing the mathematical interpolation, but yes, it's reasonable to come to those conclusions that at that 50 and 5, linear interpolation would tell you that we might go to 0.9x coverage. Well, we're even below that right now, so you might have...

On prices.

We're even below that on prices. We're not -- we're way above -- I think we've shown that we can do high coverage in higher price points. So yes, we're going to be dialing the coverage dial. We don't want to go much below 1.0, but we're not scared to have 0.9 to 1.0 and we need to -- but we also need to look out over multiple years in terms of what is the expectations of price and therefore, the expectations of level of activity and the expectations of volumes in our G&P business as we make those decisions embedded in that early December guidance was levelized. I'm not sure we have the expectation of levelized yet.

Okay, that's helpful. And then I guess the other question is I mean, you spoke a little bit about the Bakken. So maybe I'll just come back to that to clarify. Obviously, there's a lot of flaring going on there. So in terms of, say, buffering the volumetric impacts, are you getting a fair amount of buffer there? And so perhaps while you say you worry about it, is it perhaps not as challenging as it would otherwise be? Is that -- maybe just a comment on that.

The buffer helps in the short term, okay? But only for the short term and we're all trying to figure out what the longer term is.

Our next question comes from the line of Matthew Legas [ph] of Challenger Capital.

It is actually Jon Keani [ph]. I just want to make sure I understand the message that you were trying to give to people with your comments about the prior sensitivities in guidance and outlook that you all had given in December and also taking into consideration some of the changes that you highlighted as well. Were you trying to say that it's important for investors to think about the distribution growth profile of the company to more of a longer-term fashion and be a little less focused on the near term? What were you trying to get across to people? I wasn't completely clear, please.

Okay. Sort of absent exactly repeating it again, I really was trying to...

You don't have to do that, I just wanted to make sure...

I was only trying to get across to people that we are going to be looking at it over the long term like we always look at it over the long term. When we make our distribution decisions, we do so with a multiyear view, looking at multiple scenarios that are likely with the best possible inputs we can get at the time. And sharing that with our board use that multiyear scenario and the ability to cushion with coverage to try to drive our distributions and therefore, our dividends, as smoothly as possible. I think we've got a pretty good track record of doing that. And so I took the December 10 which provided some information of how we saw the world at that time and our best estimates, and try to repeat how we're going to always think about our quarter-by-quarter distributions and therefore, dividends with a multiyear view. That's all I was trying to get across and I'm not trying to imply anything else.

Okay. And then as far as the producer volumes are concerned, you made some comments about producer volumes. And what's your sense on how that's trending? Is it just difficult to ascertain right now? Or what are your thoughts on it?

Yes. I think it is difficult to ascertain. I've got many producer friends, many producer customers that I have the conversations with. So I'm generalizing and I don't want to offend anyone by generalizing, but the first half is a lot clearer than the second half because the second half will be more impacted by the actual activity levels that they're doing, call it, in the second quarter. And then those activity levels in the second half will impact how we feel about '16. And many of them, whether they're admitting to it or not, have their own version of multiple plans because the price outlook is so uncertain, and I use that term outlook broadly. When they break to the middle of the year, their outlook will be influenced by their own interpretation of supply and demand and what it's looking like and will look like by the forward curves and what that's telling them. By their own leveraged position, broadly, producers want to be living within their cash flow right now. So that's the difficult calculus. It's large in uncertainty as through any cycle we've seen, but we're also really early in the cycle.

Right, that makes sense. I think I see what you're saying. And last question I have is, back to your comments about smooth distribution growth, you all have obviously worked hard to make sure that you have a strong balance sheet. And I think in the past that obviously, really had -- probably hadn't been something that was too much of a consideration considering the direction that was moving in. Over the next 12 to 24 months, is there a little bit more focus on that and how you decide and the board decides where the distribution should grow? Or do you feel that that's moved so far in the right direction that it's really just more about coverage?

First of all, I know we had a very long call, okay, trying to provide a lot of that information, correct some mistakes that might be made out there about what our leverage looked like and what sort of liquidity we had, and it will also be in the record for everybody to look back at. That's important. We managed our balance sheet very, very carefully and I think, very conservatively. The way we've done that in the past isn't going to change in the future. And similarly, we try to manage our coverage on the equity side carefully and conservatively.

Our next question is from the line of Matt Niblack of Hite Asset Management.

This is actually Andy Gupta. A question about the vote coming up next week. I guess, how confident are you in that vote going forward? And have you had any calls from shareholder groups at TRGP expressing any dissatisfaction with the deal?

I'm very confident in the TRGP vote. Anyone who's been involved in deals like this knows I get to see them.

Okay. I guess, any comment on the second part of the question?

Have I gotten any calls from shareholders? No, I have not recently. We made a concerted effort to try to address all natural questions of people with energy portfolios and the price dislocation, major shareholders with our position beginning with the price shock when interest really went up, and after the first of the year as people were thinking about the upcoming vote. I'm hoping we've addressed all those questions publicly at conferences or one-on-one. All we're doing is just pointing to publicly available information to say here's how it's going to work and why we're very confident and my very confident that's been there from day 1 is even more very confident.

Understood. And one other question is, you'd earlier made comment about buying compressors, displacing lease compressors as you think about capital plans. Can you just elaborate on that a little bit more? Why don't you use that CapEx for your other projects or save that? Are you expecting that much of a return on the CapEx for the compressors?

Yes I don't mind describing it but I'm going to describe it generally and not by any particular vendor. We've always in growth mode in almost every area operated with a owned and leased portfolio. The leased allows you to manage variability. Compressors get moved around within fields. Targa has 2 of its own compressor refurbishment shops, so we have spares. And having a spare to instantly put back in when something goes down is an infinite return, it's the right use of capital. Our replacement of leased compressors, let's say, I was buying some for the future and certainly not don't need them this fast, but I don't have to create a large inventory. I just get rid of a leased compressor. And I also approach, when I have a couple in my pocket, I will tend to approach all of my vendors for lower terms on these sort of evergreen not termed, but just month-to-month compressors. And if I don't get a lower rate, guess which one I replace? It's not complicated.

Our next question comes from the line of Faisel Khan of Citigroup.

I'll just keep it quick. I just had a question on the hedges for 2015. On a pro forma basis, you said that roughly 40% of your volumes are POP pro forma for the transaction. Going forward, can you just give us a little bit more idea of what the -- how much of that volume is hedged again on a pro forma basis for '15 and at what price? Or did I miss that in the press release?

No. You'll see our hedge schedules, we will put it in our K when we file it. It will be out today. Atlas is going to be having theirs out, so it will be towards the end of the month. We didn't give you the pro forma numbers, we gave you our standalone. It was 55% hedged in '15 on gas and 45% hedged on condensate, 12% on NGLs. Atlas has their hedges disclosed on their last 10-Q. Again, it will be updated when their K is filed here recently. They do have more hedges than us on the natural gas side.

Any reason why on the preview guidance, only 12% of your NGLs are hedged for '15 and why not more of it?

I mean, as we've described to investors for some time, Targa -- hindsight's 20-20 -- has been less hedged on LPGs because of our perceived upside versus downside, but more so our internal view shared with our Board of Directors, that a large portion of that volume being ethane is essentially getting natural gas price. And secondly, our propane which is the next largest volume, as you know, call it to the nearest 10%, 20% that the propane piece of this has an interesting offset relative to our opportunities for propane exports. So I would not call it a natural hedge. Understand that, that would be an imprecise term but directionally, it is a directional offset. And then it's a function of just how much do you have of one or the other. It's the reason we're more likely hedged on propane.

And that 12% assumes...

By the way, that's why Matt says the best way for you to think about hedging is we'll be hedged at least as much as the sum of the parts when you put Atlas and Targa together. Probably more so for the combination but not thinking about it dramatically differently except to make sure that we stay disciplined.

Okay, and then the 12%, that means that includes the assumption of ethane being rejected across your system too, right?

Yes, we take that into account. It's an estimate. It doesn't change it too much.

And we talked about this before. We can reject in some of our newer plants. The propane penalty is generally too high to reject in some of our older facilities, and so we're actually -- we're managing that every day to watch it. But even if it's not rejected, okay, it's near gas pricing, okay?

Our next question comes from the line of Helen Ryoo of Barclays.

Just some quick items. So on CapEx, you provided a preliminary number. Just wondering if there's any wiggle room to reduce that preliminary 2015 CapEx if needed during the year. And then the second question is if you add in Atlas' CapEx, and my sense is that there's not -- with the new Buffalo plant that got pushed out in Permian, doesn't look like there's a whole lot of spending at Atlas planned for '15, but could you provide some sort of an estimate on a pro forma basis?

I'm not comfortable providing the estimate on the pro forma basis. I will instead, give color that I think is helpful. We've taken -- early in January, we came out with guidance that showed that CapEx might be that 60% to 80% of the previous numbers and we showed you where the primary ranges were on our investor presentation. It's still out there and when you say more if needed to, what that range is reflecting is our smart delay in downsizing associated with what is necessary to meet the customer needs. And back to other questions, we'll get adequate returns for that, as good a returns for that. It's a reasonable assumption and it's a reasonably informed assumption on my part that Atlas does not look that different. I happen to understand the delay in the Buffalo plant pretty well. There hasn't been that much money spent, and it going slower makes a lot of sense. In fact, if it's going slower and then suddenly prices pop up and Pioneer needs volumes faster, the new merged company is going to be able to help them because we can pipe it all together and get it to High Plains, which currently has capacity available. That's just the benefit of having more assets and having what will soon be a super system in the Permian Basin. So CapEx will be reduced to what is necessary to meet our customer demand and that will naturally occur project by project, some of which will be visible to you.

That's helpful. And then on the Longhorn and the High Plains plants, are you -- what is the utilization of those plants? Is it possible to give out an expectation when those plants would fill up? Or given the uncertainty on the producer side, that's a little bit difficult to talk about?

It's a little difficult to say when it fills up. I do want to take a step back and say, do you remember that both of those are now parts of multi-plant systems. It also is our newest plant, so I tend to put more volume to them because it gives me better control of that ethane rejection, but they were put into systems that were full and have importantly contributed to our ability to handle volumes, including volumes all the way from Sand Hills across the Midland pipeline, if that's helpful. And know, in terms of when they might fill up, I was a little concerned about our North Texas -- not concerned, starting to plan for what's next in North Texas, that's been slowed down a little bit, for example, by just that current activity levels. And then in the Permian, our combined portfolio, the Atlas plant delay is reflective of slower-than-anticipated producer drilling, and that will work nicely with the rest of the Targa portfolio.

Okay. And then just lastly, on the LPG export volume you reported for this quarter, does that include any short spot volume or, I don't know if you would call it noncontracted volume?

I can assure you, we have no noncontracted volume going across the dock. We do have some shorter-term contracts and we aren't disclosing the mix of that. Though I think we provided information that we contracted for more across 2014 for 2014 and for multiple years.

And with no further questions in queue, I'd like to turn the conference back over to Mr. Joe Bob Perkins for any closing remarks.

Thank you very much, operator. Thank you for all of your patience. I know we had longer prepared remarks to try to help with your questions, and we are happy to have helped with the long list of questions. If you have any other questions, feel free to give me a call, Matt a call, Jen a call. We appreciate your interest. Good day.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may all disconnect. Have a great rest of your day.