Targa Resources Corp (TRGP) 2014 Q4 法說會逐字稿

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 would 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 would 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 the might include the Company's or the Partnership's expectations or predictions 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 would 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 three 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 had 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 standalone.

Targa is adding scale and diversity with very well-positioned assets and very good people. And our well-received access to the capital market 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 a record year also.

Record logistics and marketing division operating margin of $695 million. Record gathering and processing division operating margin of $450 million. Record distributable cash flow of $763 million.

Record 69% of margin from fee-based operations in 2014 and a record 76% in the fourth quarter of 2014. And of course, increasing distributions and dividends to record levels for both TRP and TRC.

We placed a number of key projects in service in 2014, including our 200-million-cubic feet a day Longhorn plant in North Texas, our 200-million-cubic feet a day High Plains plant in SAOU, the Midland County pipeline connecting our Sand Hills system to the High Plains system. And please note that this pipeline also runs through the Atlas West Texas system.

And we completed the second phase of our international export expansion. Completing that second phase of our export expansion contributed to another year of record operating margin for our logistics and marketing division, up 64% compared to 2013. Daily LPG export volumes increased by 81% in the fourth quarter of 2014 versus the fourth quarter of 2013.

We were able to move approximately 6.8 million barrels per month of propane and butane across our dock during the fourth quarter and want to provide you with some color around that business, as our Mont Belvieu and Galena Park assets outperformed our multi-period effective capacity of 6.5 million barrels per month.

With a fourth quarter average of 6.8 million barrels per month, our estimated multi-period 6.5 million barrels per month effective capacity may ultimately prove to be conservative. We have only four months of reported performance since we completed the second phase and we will have a much better handle on multi-period capability after a full year of operation.

LPG export cargoes from our facility are going predominantly to the Americas, but an increasing number of vessels are also moving to the Mediterranean, European, and Eastern markets.

As you can tell, our facility has been heavily utilized and I can report that we have not had a shift cancellation since the first quarter of 2014. Now contracting demand may not be as heated as it was at this point last year, but through the fourth quarter, since the price shock and year to date, we've continued to add long- and short-term contracts at similar terms to our existing portfolio.

In May of last year, the last time that we provided export contract numbers, we said that we had 4.2 million barrels per month of LPG exports contracted for the remainder of 2014 and that we were similarly contracted for 2015. Today, while reluctant to disclose much about our export contracting for competitive reasons, we will say that we are in a better contracting position than last year at this time, with over 4.2 million barrels per month contracted in 2015.

And we will say that for 2016, we are similarly contracted on a one-year forward basis as we were in May last year. Also based on that contracting, interest and demand to date, and our performance history, it is our view that facility utilization may be similar in 2015 to what we saw in the second half of 2014.

Moving to our field gathering and processing segment, in 2014, we saw continued strong producer activity across our areas of operation. Volumes were up across the board and we continue to benefit from increasing contributions from the Badlands assets.

Our 40-million-a day cubic feet Little Missouri Train 3 processing plant expansion in the Badlands is ready to start up and has been waiting on a third-party NGL pipeline. I'm assured that that pipeline connection and the plant start up are now expected for next week.

With increases each quarter, the Partnership's full-year 2014 distribution increased 9% over 2013, consistent with our full-year guidance that we expected to be at the high end of the 7% to 9% distribution growth range -- the high end of the original 7% to 9% distribution growth range. At the TRC level, our full-year 2014 dividend was 29% higher over 2013 and above our original 25%-plus dividend growth guidance for the year.

As a result of our strong performance in 2014, we were able to deliver on our distribution growth guidance while also building coverage. Our 1.5 times distribution coverage for the fourth quarter and 1.5 times distribution coverage average for 2014 reflects the strong performance of our business and positions us well going forward, given the downturn in commodity prices.

Similarly, Targa's 2014 performance positions us very well from a liquidity and debt perspective, with a low compliance debt coverage ratio and no borrowings on our $1.2 billion revolver at year end.

At this time last year, you will recall we were discussing some of the factors that were impacting the domestic propane market and the propane price spike. What a difference a year makes. Now we are facing and talking about commodity prices that have decreased significantly over the last four months.

While I don't pretend to have a unique view into what is going to happen with commodity prices, we are managing the Company with the working assumption that 2015 average prices may be somewhat higher than we have experienced to date, but not significantly. And we are managing the Company to prepare for a 2016, where commodity prices may be only modestly higher than 2015.

As you are aware, there continues to be a lot of uncertainty among our producer customers concerning their level of activity and the resulting volumes. With a significant portion of our business in the field gathering and processing area impacted by that uncertainty, until we have greater clarity on expected producer customer activity levels for 2015, we cannot provide greater clarity on our expectations for the year, beyond reiterating what we have already stated publicly. And I will do some of that.

When we announced the Atlas transaction in October 2014, we provided guidance for pro forma distribution growth of 11% to 13% at the Partnership and dividend growth of approximately 35% at TRC, obviously based on different price environment and the expected producer activity and resulting volumes at that time and in that price environment.

In early December 2014, Targa issued a press release that provided additional information concerning potential distributions, dividends, and coverage, including comfort that our previous pro forma distributions and dividend guidance under a couple of price and price-related volume scenarios, including a scenario on the lower end, described as: number one, average 2015 prices of $60 per barrel of crude oil, $0.60 per gallon for NGLs, and $3.75 per MMbtu for natural gas.

Secondly, low-single digit growth related to that price outlook for 2015 over our Q4 2014 pro forma field gathering and processing volumes. And thirdly, and not necessarily a direct price relation, a conservative statement that we were only including LPG export volumes that were already under contract as of the date of the press release. So with that scenario, we estimated distribution coverage of approximately 1.0 times.

The December press release indicated our comfort with reduced coverage in a lower commodity price environment. We believe it also provides investors with another data set, including commodity prices, volume assumptions, and resulting coverage, making it possible to mathematically extrapolate beyond the points provided for the potential impact on coverage at nearby price levels.

We want to reiterate what we have said about how we will think about our distribution and dividend decisions. Consistent with our history, we will continue to recommend quarterly distribution and dividends to our Boards using a multi-year view with our best available information at the time.

Using a multi-year approach helps us to continue to try to deliver a smooth distribution and smooth dividend track record. We approached the announcement of Targa's standalone distribution and dividends on January 21 in that same way. And we will do so again when we approach the Targa distributions and dividends for the first quarter. Those will be announced sometime in mid-April, of course after the merger close at the end of February.

As we have demonstrated in the past, we are very willing to have coverage go below our long-term target of 1.1 times to 1.2 times, assuming we and the Board have comfort in an overall outlook that eventually returns to our long-term target.

Now today, prices are meaningfully lower than the scenarios presented in the December press release. At this point, while still faced with significant uncertainty around pricing and producer activity, we believe that the previously provided scenarios and a reiteration of how we will address distributions and dividends allows our investors to understand those future decisions in light of those uncertainties. We will continue to monitor price outlooks, producer activity levels, and we'll update you with additional information if and when appropriate.

For our next quarterly distribution and dividend declarations within current prices and with the best information we have for price and producer volume outlooks at the time, you can assume that we will decide the quarterly distribution and dividend and coverages that are related to that with a multi-year outlook in mind. And we may provide additional explanation of our thinking at that time.

I would like to conclude my introductory remarks by thanking the entire Targa team and for the Atlas team, soon to be the Targa team, for a successful 2014. And for their hard work that began last quarter, preparing for the current price environment.

When we had in all-employee meeting in early December, many of those employees were already working on three priorities for 2015: increased cost management, focus on capital investment efficiency, and looking for other opportunities that price dislocations bring to our business.

Since then, the entire organization -- and I understand that a similar signal was sent to the Atlas organization -- has been focused on those three priorities, while continuing to meet the needs of our customers. So as we report on the close of 2014, it feels appropriate to look back at a high level at performance over the last few years and how that performance positions us for the future.

The following simple data points are pretty impressive. 2012 adjusted EBITDA, $519 million. 2013 adjusted EBITDA of $635 million. 2014 adjusted EBITDA of $970 million.

And now, early in 2015, we are nearing the close of the Atlas transaction, adding very complementary assets in people, and resulting in a combined Targa with an enterprise value of about $19 billion in scale and diversity of businesses that strongly positions us for the future.

With those not-so-brief remarks, I will now turn it over to Matt. Matt?

Thanks, Joe Bob. I would 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 a 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 three 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 will summarize the fourth quarter's 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 2014 compared to the fourth quarter 2013 due primarily to higher export and fractionation volumes, partially offset by increased operating expenses associated with additional assets in service and higher system maintenance costs.

Export activity at our Galena Park Marine Terminal on the Houston ship channel increased again this quarter, with the second phase of our export expansion projects fully completed during the third quarter of 2014. We loaded an average of 226,000 barrels per day or approximately 6.8 million barrels per month. In the marketing and Distribution Segment, operating margin for the segment increased 47% over the fourth quarter 2013 due primarily to increased LPG activity.

Turning now to the field gathering and processing, our fourth-quarter 2014 operating margin increased by approximately 5% compared to last year, driven by the additions of our Longhorn and High Plains plants, which contributed to those increased volumes, and by higher natural gas prices, partially offset by lower NGL and condensate prices.

Fourth-quarter 2014 natural gas plant inlet for the field gathering and processing segment was 974 million cubic feet per day, a 24% increase compared to the same period in 2013. All of the field G&P businesses -- business units had higher natural gas inlet for the quarter. Natural gas inlet volumes increased by approximately 40% at SAOU, 34% at Versado, 24% at Badlands, 20% at North Texas, and 8% at Sand Hills.

Fourth-quarter results for the field segment also benefited from an increase of 78% in crude oil volumes gathered in the Badlands versus the fourth quarter of 2013. For the segment, we benefited from higher natural gas prices, offset by lower NGL and condensate prices in the quarter. Natural gas prices were 7% higher, while NGL prices were 35% lower and condensate prices were 31% lower compared to the fourth quarter of 2013.

In the coastal gathering and processing segment, operating margin decreased 55% in the fourth quarter compared to last year. The decrease was driven by NGL prices that were 31% lower and NGL production that was 10% lower than the same time period last year.

With that, let's now will briefly to capital structure and liquidity. AT December 31, Targa was in a very strong position from a liquidity standpoint. We had no outstanding borrowings under the Partnership's $1.2 billion senior secured revolving credit facility due 2017.

With outstanding letters of credit of $42 million and cash on hand of approximately $72 million, total liquidity was approximately $1.23 billion.

At December 31, we had borrowings of $183 million under our accounts receivable securitization facility. And during the fourth quarter, we extended the term of our AR facility to December 2015 and maintained the same pricing. In October 2014, we successfully issued $800 million of 4 1/8% senior unsecured notes maturing in November 2019.

On a compliance -- on a debt compliance basis, which provides us adjusted EBITDA credit for material growth projects that are in process, but not yet complete, and utter certain adjustments, our total leverage ratio at the end of 2014 was a very strong 2.6 times debt to EBITDA and well below our stated target range of 3 times to 4 times.

Pro forma for the closing of Atlas transaction, we expect this leverage ratio will be at approximately the midpoint of our target range. And for the remainder of 2015, we expect to be within or around the 4 times area of our target leverage ratio range.

In the fourth quarter, we received gross proceeds of approximately $153 million from equity issuances under our at-the-market equity program, which allows us to periodically sell equity at prevailing market prices. And in 2014, we raised approximately $413 million of gross proceeds under our ATM program.

We were very pleased with our ability to access to capital markets early in 2015, even in this challenging commodity price environment. When we announced the Atlas transaction in October of 2014, we had $1.1 billion of committed financing in place at TRC through a revolving credit and Term Loan B facility.

Subject to close on the transaction, we have entered into agreements for a $670 million senior secured revolving credit facility, larger than our initial expectations for a $350 million facility due to a strong bank market support for Targa. The increased revolver obviously reduced our borrowing needs for the Term Loan B, which we have now syndicated and priced a $430 million Term Loan B offering.

In January, we also issued a $1.1 billion of 5% senior unsecured notes maturing in January 2018 at TRP, the proceeds of which will be used to fund tender offers for some of the outstanding Atlas pipeline notes. We also received commitments to increase our TRP revolver from $1.2 billion to $1.6 billion.

In the equity markets so far this year, we have raised gross proceeds of approximately $13 million under our ATM program and expect to continue to utilize the ATM to meet our equity funding needs in 2015.

With all of the above transactions committed and syndicated, we currently have approximately $2.9 billion of liquidity at TRP and expect to have over $800 million of liquidity after transaction close. At TRC, we expect to have over $200 million of liquidity and a leverage ratio of approximately 4 times.

Next, I would like to make a few comments about our hedging and capital spending programs for the year. As Joe Bob mentioned at the beginning of our call, our fee-based operating margin was a record 76% in the fourth quarter of 2014 and we averaged a record 69% of margin from fee-based operations in 2014. Pro forma for the Atlas transaction, and at today's prices, we would estimate approximately 70% of fee-based margin for 2015.

For the non-fee-based operating margin relative to the Partnership's current equity volumes from field gathering and processing, we estimate that we have hedged approximately 55% of 2015 and 25% of 2016 natural gas volumes, approximately 45% of 2015 and 30% of 2016 condensate volumes, and approximately 12% of 2015 NGL volumes. Pro forma for the merger with Atlas, our fee -- our non-fee-based operating margin will increase modestly, but the Atlas G&P commodity exposure is more hedged than Targa and the combination will continue to hedge in a manner consistent with the sum of the parts.

Moving to capital spending, in our January investor presentation, we published a preliminary estimate of $490 million to $675 million of growth capital expenditures in 2015. This still represents a reasonable range of standalone Targa growth CapEx expectations.

Next, I will make a few brief remarks about the results of Targa Resources Corp. On January 21, TRC declared a fourth-quarter cash dividend of $0.775 per common share, or $3.10 per common share, on an annualized basis, representing an approximately 20% -- 28% increase over the annualized rate paid with respect to the fourth quarter of 2013.

TRC's standalone distributable cash flow for the fourth quarter of 2014 was $38 million and dividends declared were $33 million. At year end, TRC had $102 million in borrowings outstanding under its $150 million senior secured credit facility and $9 million in cash, resulting in total liquidity of $57 million.

That concludes my review, so now I'll turn the call back over to Joe Bob.

Thanks, Matt. I will 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 standalone 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 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.

We're 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 the 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 petchems and other end users. While the recent price shock creates some uncertainty and may slow timing of sufficient contracting, the relative economics continue to appear attractive.

At Targa, as I said, our day-to-day operations in commercial focus is on managing cost and spending capital efficiency, while also looking for opportunities the price changes may create. We are looking forward to the close of the Atlas merger and the ability to work more closely to identify and pursue those same opportunities while we continue to serve our customers' needs.

Lessons learned in 2008 and 2009 are being employed again today. Most of our employees automatically pulled out those playbooks and are working together to again implement best practices while also explaining to new employees that Targa is a very sound ship for stormy seas. And a ship that can take advantage of opportunities as we navigate those stormy seas.

The experienced employees remember that Targa can make a significant difference on cost savings and capital efficiency in such a time. And that Targa actually added employees while saving money related to those employees in 2008 and 2009.

Before we open up the line to questions, I would just like to thank the Targa team again for another successful year in 2014. Our successes in 2014 have positioned us well for 2015 and 2016. And in the lower price environment of 2015 and 2016, Targa will manage the Company and manage its distributions and dividends the same way that it has in the past: with a multi-year view under multiple scenarios.

So with that, we will open it up to questions. And I'll turn it back to you, operator.

(Operator Instructions) Jeff Birnbaum, Wunderlich.

So I appreciate the additional color on the call this morning. And I understand obviously some of the conflicting demands that you are giving -- the desire for more color in a very uncertain environment.

But I just wanted to ask -- am I hearing you correctly that 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 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 2015 distribution and EBITDA guidance?

Jeff, you've covered a few things there. I think you are 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 are 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 are using a working assumption for managing the Company that says that prices on average for 2015 may be modestly better than what we have experienced in a month and a half today. And with that working assumption, if 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 come with your own modeling assume that we are not concerned with something like 1.04 times or 0.9 times coverage for quarter or for 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 then 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.

Okay.

Is that helpful?

Yes, no, that is, Joe Bob. Thank you. And I guess I just wanted that -- one additional question on CapEx here. It sounds like full speed ahead with Train 5 and permitting for Train 6.

So I guess the read there is is there any other color you can give I guess on -- at least in terms of the CapEx for the field G&P, how -- I think you had mentioned it a little bit, Joe Bob, in your comments, where -- how you can kind of see that evolving 2015 and 2016?

Sure. 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 will do that combined with the Atlas assets.

For example, in the Permian, even better, right? Because we've got an even bigger supersystem 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 standalone reducing its capital pre-price 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 might actually spend even less capital. Put the assets together, 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 still 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. That's, again, the question of when, not if, on Train 6 and we will add that capacity when it's appropriate for supply needs.

The Channelview project in our downstream I expect will be spending about that same amount of capital, though we are stepping back and studying, or maybe a little bit more, with the same EBITDA expectations -- excuse me, better EBITDA expectations that we had prior to the end-of-year renegotiation. Did that help?

Yes, that's very helpful. The one follow-up I would have is -- I guess it sounds -- to the extent you can give color on it that it seems reasonable that perhaps you would see more -- more of a -- less CapEx kind of or infrastructure additions on the G&P side from 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 that I'm going to be slowing down is North Dakota.

Got it. Thank you very much.

Brad Olsen, 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 may 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 will say yes, I can help on the first part and no, I don't intend to on the second part.

Our -- 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 1 times, not 1.5 times. And what that means is we 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 reduce how much time we're spending with contractors, who, in the run and gun times, are doing work that Targa employees could otherwise do. And believe me, that costs a lot more than 1 1/2 times.

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 2008, 2009. I'm interested in cash wherever we can get it.

Compressors. We are installing our own compressors and having to dislocate compressors we are leasing 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 went up with oil prices. Believe me, we are be among the most aggressive at pushing it down with oil prices. And that ranges from chemicals to trucking fees, etc., as they 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 first 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 2008, 2009.

Now I know you would like to know the number. I don't intend to disclose that today, but it is a nice compensating factor, as we are working in a lower price environment and we know how to execute.

Got it. That's great color Joe Bob. Thanks. One follow-up is on the investment multiple side. When we think about processing plants in G&P activity, where historically, you saw it 5 to 7 times-type multiple, that obviously comprises, at least partially, a commodity lever 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 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 a 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 5 times to 7 times -- and we have often said it -- is how we characterize the major announced projects on our capital budget rollout that we present to the markets. You all all know that there are a lot of smaller projects on the list and they do considerably better than 5 times to 7 times when you are leveraging existing infrastructure.

So first of all, in a capital efficiency-focused world, producers aren't making great big changes. They are making more incremental changes and we are 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 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 on producers to existing processing plant capacity. I can assure you we do better than 5 times to 7 times 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 downsize 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. Thanks, again.

JR Weston, Raymond James.

I just wanted to touch back on LPG exports. We are 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're done quite a bit. I expect that interest to continue.

If we sort of talk about the more across our export dock, I can't get much more across our export dock right now. I am 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 you know, 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.

Great, thank you. Appreciate the color. Just kind of switching gears a little bit and just thinking about the fact the US is really going to have a glut of refined products here on the Gulf Coast that do need somewhere to go.

And just maybe your color on how you're looking at additional petroleum logistics opportunities. Maybe more middle distillate residual fuel or [just the luxford] 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 ship with the right dock. That's really about all I would say about it right now.

Okay, great. Thank you. Appreciate that. That's all I had.

Shneur Gershuni, 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 made some volumes assumptions based on the lower commodity environment. Yet you kind of still have a mid-single digits 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 are seeing volumes go up, other basins where you are thinking volumes go down. And is that still consistent, given the barrage of E&P companies that have been cutting CapEx? Were you anticipatory of them basically hitting some of those regions and so forth? So I was wondering if you could talk about the 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 will be a lot smarter as we actually see what happens.

And that had built into it what are producers doing in the first half and what did we think they might do in the second half. And we will have -- we will 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 ordered 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 worried the most about, I mentioned in a previous answer, is North Dakota, who is getting hit both by lower prices and a differential issue.

Fortunately for Targa for 2015, we've got -- 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 flares.

The cast is just flaring or the whole well is shut in, because they can't flare anymore waiting for that plant. We are also waiting for some write away 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 I'm -- that's kind of on my most worried list. And we've tried to be conservative about what we thought that would look like as we put together those December -- a lot is 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 I think a follow-up to some of the questions I think Brad had asked. Everybody has 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 indicated a need to do some major cost overhaul and restructurings. Obviously, in your fourth-quarter results, we saw some changes to your long-term incentive plans.

I was wondering if that's something that you are aggressively pursuing now? Is that something we will 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 could sort of give us some color on how you are going to further manage or potentially manage costs 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 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 two very well-positioned companies, both of which are short of people.

Now the good news is we've got high talent in both companies, so 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 do 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 are laying off folks. Not necessarily their laid-off employees, but the employees who don't feel so good about the ship they are on when they saw other people getting laid off.

I really believe that's where we are in my outlook for 2015 and 2016. If it goes on longer than that, everybody is 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 redoing the Atlas debt gets you half to two-thirds of that. There are lots of different ways we can save the dollars.

So we will overdeliver on $20 million to $30 million, but what we won't be doing -- oh, and we obviously saved some significant multiple public company costs. There won't be any Philadelphia or New York overhead. I will let you all go figure out how much that was. That might be a way to save a good bit as well.

So we get certainly more than the $20 million to $30 million estimated, but I'm not going to be bringing to investors -- and I know you might like to have it -- how much are we losing on price? How much are we making up on cost savings? What was our original synergy. What was the stuff we didn't know about?

I can absolutely guarantee that the stuff we know about, the stuff we suspect, and the stuff we haven't found will be a whole lot better than the $20 million to $30 million. And you know what? We need a whole lot better than $20 million to $30 million because prices are clobbering us right now.

But that G&P business is only part of our business. Call it half of our business. And other side isn't being impacted very much. That's the big benefit of diversity and scale.

Cool. No, thank you very much for the expanded color. Have a great weekend.

Sunil Sibal, Global Hunter Securities.

Congratulations on a good solid quarter. A lot of my questions have been addressed already, but I had a couple of housekeeping items. First of all, on the non-cash incentive plan reduction that you benefited from in fourth quarter, was kind of wondering your SG&A fell about $15 million sequentially.

So how much of that $15 million [vaulted] non-cash investment expense savings? And then how should we think about the 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 -- 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 would say the change that you saw in the fourth quarter was related to the LTIP plans -- or the delta, which related to the price of basically NGLS and TRGP. Not a restructuring. And that makes up a lion share. And that was actually -- there were some offsets going the other way on some of the increases and some other overhead costs.

Okay. So basically what we can do is see the delta and project it with the prices on units for TRGP and NGLS, I guess.

Yes, I think you could from a modeling perspective.

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

That's both in our gathering processing and in our downstream business. It was not -- as Joe Bob mentioned, it was not LPG exports. But there's some small amounts 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, you know we are doing that with term of art. It's a reservation fee --

Fee or a volume. Yes.

Yes. It's a full family of those. 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 to that 90%. It's still -- that should not be viewed as any indication that we are not highly utilized in the fractionation business.

And -- okay, no, that color is helpful. And then lastly, I was wondering if you could talk a little bit about M&A environment in the current situation and how you guys are thinking about that post-closing of the APL acquisition.

And any particular type of asset sets, which may be more opportunistic for you guys? I think you mentioned about dislocations leading to opportunities and I was wondering if that's probably more organic versus M&A?

I'll never want to think of M&A instead of organic. We look at M&A also. So 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 are looking for those. Likely to be smaller, very interested in bolt-ons, and 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 will be some larger things available. Targa is in good position to look at it, but we will 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.

Sort of starts by making sense with our existing asset base in our wheelhouse of the businesses that we are currently running. And sometimes we look at larger stuff that has more of that in a package.

All right. That's very helpful. That's all I had. Thanks.

Jerren Holder, Goldman Sachs.

I just have one quick one. We saw another mission company mention renegotiating some contracts for some evergreen T&F terms that were underwater. Any opportunities for you guys as 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 would say there some opportunities for that, but the lion share of our fractionation contracts have been redone relatively recently.

We don't have much coming to term.

All right, thank you. That's it for me.

John Edwards, Credit Suisse.

Yes. Good morning and congrats on a nice quarter here in a tougher environment.

Thanks.

I wanted 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. Does that -- if you could answer those two questions real quick.

Yes, sure. I think I'm going to regret having said the playbook, but the reality is that's what our area managers said. I had -- as soon as the note went out after the end of the first year, he said I've already pulled out my notes from 2008, 2009. And another one said I've got the playbook. I am sharing it with others.

I am -- 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 manages 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. Things cost more. We will be saving significant dollars from our suppliers, our vendors, contract labor, our own overtime labor.

Products and materials will get meaningfully cheaper. We've already had proposals -- some of those proposals we have asked to be reduced on things like chemicals. If oil is a primary component and an excuse for increasing it and it's cut in half, can't imagine that we can get a pretty significant reduction in chemical costs, for example. Or engine oil. 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 to 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 two other companies are a freebie for us. We will be keeping a separate set of financials for some outstanding noteholders. That's not hard to do -- 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 the -- 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 $50.05 linear interpolation would tell you that we might go to 0.9 times coverage. Well, we're even below that right now. So we might have --

On the prices.

We're even below that on prices. We are not -- yes, we are way above (laughter). I think we showed that we can do coverage style in the higher price books.

So yes, we're going to be dialing the coverage dial. We don't want to go much below 1.0 times, but we're not scared to have 0.9 times to 1.0 times. And we need to look -- 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 -- you spoke a little bit about the Bakken. So maybe 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 -- if you could comment on that.

The buffer helps in the short term. But only for the short term and we are all trying to figure out what longer term is.

Okay. All right, great. Thank you so much.

Matthew Ligas, Teilinger Capital.

Good morning. Hi Joe Bob, it's actually John Kiani. Can you hear me?

Hey John. Yes, I can.

Thanks for your comments earlier. I just want to make sure I was trying -- I understand the message that you were trying to give people with your comments about the prior sensitivities and 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 in 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. Well, absent exactly repeating it again, I really was trying to --

Yes, you don't have to do that. I just wanted to make sure I understood you --

I was really 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 multi-year 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 used that multi-year 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 though I took the December 10, which provided some information of how we saw the world at that time and our best estimates, and tried to repeat how we're going to always think about our quarter-by-quarter distributions and therefore dividends with a multi-year 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 producer volumes are concerned, you made some comments about producer volumes and what is your fence on how that is trending? Is it just difficult to ascertain right now or what are your thoughts on it?

Yes. I think there is -- 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 are doing, call it, in the second quarter. And then those activity levels in the second half will impact how we feel about 2016.

And many of them, whether they are admitting to it or not, have their own version of multiple plants. Because the price outlook is so uncertain. And I use that term outlook broadly.

When they get 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 stat's telling them.

By their own leverage position, broadly, producers want to be living within their cash flow right now. So that's the difficult calculus. As large and uncertainty as -- through any cycle we have seen, but we are 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 has -- probably hadn't been something that was too much of a consideration, considering the direction that was moving in.

Over the next 12 months to 24 months, is there a little bit more focus on that in how you decide and the Board decides where the distribution should grow? Or 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 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 a record for everybody to look back at. That's important.

We manage 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.

Okay. Thank you.

Matt Niblack, HITE Asset Management.

Hi. Thanks for taking our question. This is actually Andy Gupta. 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 am very confident in the TRGP vote and anyone who has 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 a 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 am hoping we have addressed all those questions publicly, at conferences or one-on-one, where all we are doing is just pointing to publicly available information to say here's how it's going to work and why we are very confident. And my very confident that's been there from day one is even more very confident.

Understood. And one other question is you had earlier made a comment about buying compressors displacing leased compressors as you think about your capital plans. Can you just elaborate on that a little bit more? Why not use that CapEx for your other projects or save that? Are you expecting that much of 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 have 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 two of its own compressor refurbishment shops, so we have spares. 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 lease compressors -- let's say I was buying some for the future and suddenly don't need them as fast. I don't have to create a large inventory. I just get rid of a leased compressor.

Sure.

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.

Yes, no, that makes sense. Thanks so much for taking the questions.

Faisel Khan, Citigroup.

I'll just keep it quick. I just had a question on the hedges for 2015. On a pro forma basis, you said 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 2015 and at what price? Or did I miss that in the press release?

No. We -- you will see our hedge schedule. We will put it in our Form 8-K when we file it. It will be out today. Atlas is going to be having theirs out -- it will be towards end of the month.

We didn't give you the pro forma numbers. We gave you our standalone. It was 55% hedged in 2015 on gas and 45% hedged on condensate, 12% on NGLs. Atlas has their hedges disclosed on their last Form 10-Q. Again, it will be updated when their Form 8-K is filed here recently. But they do have more hedges than us on the natural gas side.

Okay. Any reason why on the -- for you guys, only 12% of your NGLs are hedged for 2015 and why not more of it or --

As we have described to investors for some time, Targa -- hindsight is 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 prices.

Sure. Okay. That makes sense.

And secondly, our propane, which is the next largest volume, as you know, call it to the nearest 10%, 20% -- that propane piece of this has an interesting offset relative to our opportunities for propane exports.

I would not call it a natural hedge. I 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 are more likely hedged on propane.

That 12% assumes --

By the way, that's why Matt says the best way for you to think about hedging is we will 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 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.

Got it. Okay, thanks, guys.

And we have 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 are actually -- we're managing that every day to watch it. But even if it's not rejected, it's near gas pricing, okay?

Got you.

Helen Ryoo, 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's CapEx and I -- my sense is that there's not -- with the new Buffalo plant that got pushed out in the Permian, doesn't look like there's a lot of spending at Atlas planned for 2015. But could you provide some sort of an estimate on the pro forma basis?

I am 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 is still out there. And when you say more have 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 will get adequate returns for that -- as good of 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 at 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 curve project by project, some of which will be visible to you all.

No, that's helpful. And then on the Longhorn and High Plains plant, 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. They also are the newest plants, 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 no, in terms of when they might fill up, I was a little bit 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 current activity levels.

And 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 non-contracted volume?

I can assure you we have no non-contracted volume going across the dock. We do have some shorter-term contracts. The -- and we are not disclosing the mix of that, though I think we've provided information that we contract -- were contracted for more across 2014 for 2014 and for multiple years.

Okay. All right, that's helpful. Thank you so much.

Thank you. And with no further questions in queue, I would 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 a long list of questions. If you have any other questions, feel free to give me a call, Matt a call, Jenn 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.