Targa Resources Corp (TRGP) 2015 Q4 法說會逐字稿

Good day ladies and gentlemen and welcome to the Targa Resources fourth-quarter and full-year 2015 earnings webcast.

(Operator Instructions)

As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Ms. Jennifer Kneale. Ma'am, you may begin.

Thank you, Lauren. I would like to welcome everyone to our fourth-quarter and full-year 2015 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 at www.TargaResources.com. We will also be posting an investor presentation to the website later today. I would also like to remind you that on February 17, Targa Resources Corp closed its acquisition of all of the outstanding public units not already owned by TRC, of Targa Resources Partners, LP.

Any statements made during this call that 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 provisions of the Securities Acts of 1933 in 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, 2014, and quarterly reports on Form 10-Q.

Joe Bob Perkins, Chief Executive Officer, and Matt Meloy, Chief Financial Officer, will be our speakers today, and other members of the management team are available to assist in the Q&A session, if needed. With that, I will turn the call over to Joe Bob.

Thanks, Jen. Welcome, and thanks to everyone for participating. Before we turn to Targa's results, I would like to briefly discuss the closing of our buy-in transaction, and also discuss our recently-announced $500 million preferred private placement. Targa's management team and our Boards of Directors are very pleased that we closed TRC's acquisition of outstanding common units of TRP on February 17.

From our perspective, the simplification of Targa's ownership structure may have been one of the most important transactions in Targa's, history and I want to thank our shareholders and common unit holders for their strong support of the transaction. The overwhelmingly positive results of our shareholder and common unit holder votes reflect investor understanding that this was the right move for Targa. Targa is now better positioned from a leverage, credit profile, and dividend coverage perspective, and that positioning creates financial flexibility that is exceedingly important, in uncertain markets.

Looking forward, we recognize that there are continued investor concerns around every Company in the energy industry, related to risk associated with capital markets access, risks from lower prices, risks of lower producer activity levels and volumes, counterparty credit risks, and high interest in how each company will manage their balance sheet and dividends. We will try to address each of these topics related to Targa in some detail during the call, and we will try to provide you with color on how views of our risks, mitigants, and how we think about the industry challenges that we face today.

Let's start with our financial flexibility and our financial strength. When we announced that TRC was buying TRP on November 3, we provided two illustrative scenarios. The Street consensus case, and the price sensitivity case, showing those cases over a three-year forecast period. Additionally, in our public presentations before and after that time, we have provided then-current EBITDA sensitivities for NGLs, natural gas, and crude oil price changes. One can use the information previously provided in the price sensitivity case and the EBITDA sensitivities for commodity prices to extrapolate additional scenarios for different price and volume scenarios. And in so doing, one of the likely resulting conclusions should be that Targa has financial flexibility across a wide range of potential scenarios.

Also, Targa is a solid high-yield credit and does not have rating agency-created constraints relative to maintaining an investment-grade rating. And separately, Targa has significant cushion, relative to complying with our financial covenants. That cushion, that flexibility has further increased by the preferred private placement that we announced last week.

A week ago today, we announced that we had entered into binding commitments with affiliates of Stonepeak Infrastructure Partners to purchase $500 million of 9.5% Series A preferred stock. This is a great transaction for Targa, and for our new Stonepeak investment partners; one that we structured knowing that Stonepeak and other investors share a fundamental view that the strength of Targa's asset footprint, our operational capabilities, and track record of execution, are not currently reflected in our current common stock and debt trading levels.

From our perspective, this structure accomplishes many of the objectives that we had when we announced about six months ago that we would seek alternatives to public common equity funding. The preferred pays a 9.5% dividend, and the addition of warrants provides upside to our financial partner and to Targa's common shareholders. This structure mutually benefits Targa and Stonepeak under any recovery commodity price scenario.

We stated publicly in the presentation in early September that we were going to find attractive funding sources, other than public equity, and we patiently worked to develop an attractive addition to Targa's capital structure. With this preferred equity, we're not trying to solve for any one specific variable, or achieve any one specific metric. Instead, consistent with what has been going on at Targa over the last year and a half and throughout the history of Targa, when we identify a capital market opportunity, or some other opportunity to do something to strengthen Targa for the future, we act. In this case we identified an opportunity to meaningfully improve our balance sheet and capital structure flexibility at very attractive terms.

I think this is another example of our forward-looking mindset. Similar to our small retail preferred in October, and our high-yield offering in September, this is consistent with how we have always approached the business, and will continue to do so in the future.

We know there is a significant uncertainty in the market, but one thing is certain: Targa is blessed with a tremendous workforce and a well-positioned asset set, well-positioned capabilities; we will continue to identify opportunities to improve our balance sheet, maximize our financial flexibility, and enhance our operational and commercial performance, so that we are positioned to create long-term shareholder value, regardless of the environment.

We are also very excited to have Stonepeak as an important financial partner of ours. We welcome Scott Hobbs as an observer and contributor to our Board. Scott is a 35-year energy industry veteran, and is well known by the Targa team. We expect to use the proceeds from the $500 million of preferred to reduce indebtedness, which on a pro forma basis, importantly reduces TRP's year-end compliance leverage ratio to 3.6 times debt to EBITDA, and we have approximately $2.2 billion of liquidity.

I would like to pause here for a minute, and discuss our leverage position as we see it, so that we can clear up any misperceptions that might be out there. Pro forma for the buy-in, the only real change to our capital structure is that we no longer have publicly traded units of NGLS. Our basic corporate structure remains the same, and the placement of the debt. At TRC, we have about $670 million of revolver, about $160 million of term loan B. At TRP, we have a $1.6 billion revolver, a $225 million accounts receivable facility, and publicly traded notes. There is a compliance covenant of 5.5 times at TRP, but there is no other meaningful covenant or constraint on TRP leverage, TRC leverage, or consolidated leverage.

Pro forma for the $500 million preferred, TRP compliance leverage is 3.6 times, versus that 5.5 times compliance covenant. My simple math, that means to me we have almost 2 turns of cushion. And with our long-term, often-repeated target range for compliance leverage having been 3 to 4 times, we believe that Targa is currently in a very strong balance sheet position, from a Targa historical perspective, and probably relative to others in the industry.

Compliance leverage at the Partnership level is the relevant constraint to overall Targa leverage. And we are appropriately comfortable managing Targa leverage at the TRP compliance level. As we move forward in time and pursue attractive growth opportunities, managing the resulting consolidated leverage will be one factor for consideration, and any assumption that management won't be focused on managing leverage is inconsistent with our track record.

Just as managing leverage and managing our balance sheet is consistent with the Targa track record, Targa also has a track record for outperforming relative to other controllable factors. We are never satisfied with any set of internal forecasts, and I can promise you that the decision-making associated with our Company is fluid and evolving, always seeking to outperform our internal forecasts and expectations.

We will continue to focus on taking the right forward-looking steps for Targa, trying to improve on all controllable factors for any range of potential commodity price and activity levels. We spend each day focused on long-term value creation. That is our track record, and that is our mindset.

So in the face of uncertain prices, uncertain activity levels, and related uncertain volumes, perhaps made even more uncertain by oil prices breaking $30 several times over the last month and a half, you will not be hearing a new Targa 2016 forecast. But what I hope you hear from me is confidence. Confidence that we have already taken significant steps to position Targa for success in the lower for longer environment, and confidence that we will continue to identify ways to best position Targa for the future.

Summarizing the reasons for that confidence, in the context of at the uncertainties that I just mentioned, strong 2015 results and strong business performance, driven by an exceptional workforce and a premier asset footprint. Solid year-end leverage and coverage, we finished 2015 on strong on multiple dimensions. Substantial liquidity, and impressive results in managing costs and improving margins.

Over the long term, we know that with our premier asset position, we are well-positioned to benefit from the upside potential of some of the following factors: NGL pricing improvements. Ethane and other components, and other commodity price improvements. Increased ethane extraction. Additional cost savings and continuous improvement in that area. Increased exports. Capture of new gathering and processing, and capture of new downstream volumes. Continued contract restructuring to Targa's benefit. And yet to be identified opportunities for high-return capital projects.

Let's now turn to discussing Targa's performance in 2015. Despite significant commodity price headwinds throughout the year, 2015 adjusted EBITDA was $1.191 billion, a 23% increase versus 2014. I'm going to pause on that EBITDA number for a moment, and provide some additional context. At the beginning of 2015, we developed and our Board approved a formal plan in January of last year, using the best information we had at the time for the expected performance of Targa, and including the expected impact from the addition of the assets acquired in our mergers with Atlas.

Looking back at actual prices in 2015, compared to the estimated commodity price assumptions that we used for our 2015 Board-approved plan, our adjusted EBITDA was negatively impacted by about $130 million, based on price alone. We were about $130 million in the hole, due solely to price variance. But our final adjusted EBITDA of $1.191 billion beat the 2015 Board approved plan by about $25 million.

The biggest compensating drivers for that mitigation were reduced OpEx across the asset footprint, improved contract margins, lower G&A, and better than expected downstream LPG export and storage performance. I'm incredibly proud of the collaborative work of our employees to identify best practices related to OpEx, maintenance capital, and contracts. And then applying and continuing to apply those best practices across all areas of our operations.

I am also incredibly proud of the focus of our employees to deliver savings and operational results, without sacrificing safety, or environmental compliance, and without saving today at the expense of tomorrow. Their important work and focus continues in 2016, and we expect continuous improvement in these areas.

Our 2015 results provided for a year-over-year dividend increase of 24% at TRC, and modest distribution growth of 5% at TRP, as we held TRP distributions flat in the second, third and fourth quarters, in response to the industry cycle. Pro forma for the completion of TRC's acquisition of TRP, under the price sensitivity scenario presented at announcement on November 3 and published again at December 3, we showed an estimated dividend growth of 10% at TRC in 2016 versus 2015.

If we compare today's environment to that price sensitivity scenario presented less than four months ago, strip prices are significantly lower, producer volume forecasts are lower and even more uncertain, and equity and debt market volatility and pressures have increased. So what does that mean for Targa? That means that we will continue to make decisions the way that we have throughout our history. Thoughtfully, prudently, and patiently. We have taken steps to provide Targa with cushion, which means we have time to continue to monitor markets, and to continue our dialogues with investors related to appropriate dividend strategy for Targa in this environment, and across the cycle.

For the fourth quarter of 2015, we elected to maintain our quarterly dividend of $0.91 per common share. Growing our quarterly dividend in the face of uncertainty did not make sense to us or our Board. Similarly, making a rash decision to meaningfully change our quarterly dividend did not feel appropriate to us or our Board.

We have many levers available to us, as we think about our ability to execute in 2016 if markets remain challenged, levers such as: Continued cost savings from OpEx, CapEx, and G&A reductions. Pursuing identified opportunities to enhance EBITDA through improved volumes, contracts, high-returning capital projects, et cetera. Pursuing not-yet identified opportunities to enhance EBITDA through similar cost savings or commercial actions. Consideration of asset sales or asset level joint ventures with strategic or financial partners, and of course, selected private equity placements or financing, as demonstrated by the Stonepeak transaction.

We are already pulling some of those levers, as evidenced by our result and actions in 2015 and early 2016. Other levers and actions, along with future dividend policy, will continue to be thoughtfully considered over time. So that concludes my perhaps too-long introductory remarks. Thank you for your patience, and we hope that the remarks help reinforce how we are thinking about managing Targa in the current environment. I will now turn the call over to Matt.

Thanks, Joe Bob. I would like to add my welcome, and thank you for joining our call today. Before we cover Q4 results, I just want to make sure there is no confusion about the goodwill issue mentioned in our press release from February 9.

As discussed in that release and quantified today, the Partnership identified at material weakness in the controls related to its review of the purchase accounting calculations used to estimate the preliminary fair value as of the acquisition date of the assets, and liabilities acquired in the Atlas merger. Goodwill at the merger date has been restated, and we subsequently recognized a non-cash provisional loss of $290 million associated with the impairment of goodwill in our field G&P segment. This loss was non-cash and does not affect EBITDA.

Now turning our attentions to Q4, other Q4 results. Adjusted EBITDA for the quarter was $325 million, compared to $258 million for the same time period last year. The increase was primarily driven by inclusion of TPL.

Overall operating margin increased 14% for the fourth quarter compared to last year, and I will review the drivers of this performance in our segment review. Net maintenance capital expenditures were $25 million in the fourth quarter of 2015, compared to $24 million in 2014, bringing full-year 2015 maintenance CapEx to $98 million. And for 2016, we expect approximately $110 million of maintenance CapEx.

Turning to the segment level, I will summarize the fourth quarter's performance on a year-over-year basis, starting with our downstream business. Fourth-quarter 2015 logistics and marketing operating margin was 15% lower than the same quarter last year, driven by lower fractionation and LPG export margins. LPG export margins were down 15% from the fourth quarter of 2014 when we benefited from record volumes.

On our third-quarter earnings call, we mentioned that we thought we could continue to benefit from increased ship availability, growing waterborne LPG markets and globally competitive Mont Belvieu prices for propane and butane, which we expected to result in fourth-quarter volumes being similar to the prior quarter. However, we exceeded those expectations in the fourth quarter of 2015, and exported 5.9 million barrels per month, an increase of 4% versus the third quarter of 2015. The first quarter has been strong to date, but there is variability across quarters, some seasonality, and we believe that 5 million barrels per month of LPG exports is a good estimate for 2016.

Fourth-quarter fractionation volumes decreased 12% from the fourth quarter of 2014, driven by lower volumes as a result of cold weather impacts on producer and processing plant operations, as well as some lower customer volumes, and a small amount of contract roll off. We have received questions over the last several months related to frac contract expirations, so we want to provide some additional color. Over the next three years, less than 5% of Targa's frac contracts expire, and less than 10% over the next five years.

Turning now to the field gathering and processing segment. Our fourth-quarter 2015 operating margin was up 64% versus the fourth quarter of 2014, driven by the inclusion of TPL, which more than offset the decline in commodity prices. Fourth-quarter 2015 natural gas plant inlet for the field gathering and processing segment was 2.6 billion cubic feet per day. The overall increase in natural gas inlet volumes was due to the inclusion of TPL volumes in West Texas, South Texas, South OK, and West OK, and increases in volumes at SAOU, the Badlands, and Versado.

At Sandhills, volumes were essentially flat, given the system is basically full and we continue to move volume from Sandhills to SAOU on the Midland County pipeline. Volumes declined in North Texas as a result of reduced producer activity. In the Badlands, crude oil gathered decreased to 109,000 barrels per day in the fourth quarter, a 6% decrease versus same time period last year, primarily as a result of several producer customers shutting in existing production to frac new wells late in the fourth quarter of 2015. For the segment, condensate prices were 45% lower, and natural gas prices were 44% lower, and NGL prices were 43% lower, compared to the fourth quarter of 2014. In the coastal gathering and processing segment, operating margin decreased 24% in the fourth quarter, compared to last year.

Now let's move on to discuss liquidity, capital structure and hedging. Pro forma for the $500 million preferred equity private placement with Stonepeak, Targa has liquidity of approximately $2.2 billion. As Joe Bob mentioned, this means on a debt compliance basis, which provides us adjusted EBITDA credit for material growth projects that are in process but not yet complete and makes other adjustments, our pro forma leverage at the end of 2015 was 3.6 times debt to EBITDA versus a compliance covenant of 5.5.

Our fee-based operating margin was 76% in the fourth quarter of 2015, and we had 74% of margin from fee-based operations for the full year of 2015. For 2016, we estimate more than 70% of fee-based operating margin. For the non-fee-based operating margin, relative to our current equity volumes from field gathering and processing, we estimate that we have hedged approximately 40% of 2016 and 20% of 2017 for natural gas volumes, approximately 40% for 2016, and 20% for 2017 of condensate volumes, and approximately 20% of 2016 and 10% of 2017 NGL volumes. We have continued to look at opportunities to add hedges, and expect to add some hedges over time through a combination of swaps and cashless collars.

Moving to capital spending, in our January investor presentation, we published a preliminary estimate of $525 million or less of net growth capital expenditures in 2016, with approximately $275 million committed to four major products: CBF Train 5, the Noble crude and condensate splitter, the Buffalo plant in West Texas, and the joint venture with Sanchez in South Texas. All four major projects will contribute to cash flow in 2016.

We have another $250 million of previously identified projects, and expect to spend at least $175 million of this amount. The largest part of that capital is expected to be spent in the Badlands, where we will continue to build out our infrastructure, and where as you've heard from us many times before, we have been delayed by right of way on the Fort Berthold Indian reservation.

The Badlands growth capital will add infrastructure to connect producing gas and oil to our system, natural gas volumes being flared, and crude oil volumes being trucked. These projects result in immediate additional cash flow, and have a quick payback. Similarly, any additional capital spent in this category with will generally only be spent if the returns are significantly in excess of our funding cost, and will likely generate near-term cash flow.

Next, I will make a few brief from about the results of Targa Resources Corp. On January 19, TRC declared fourth-quarter cash dividend of $0.91 per common share or $3.64 per common share on an annualized basis, representing approximately 17% increase over the annualized rate paid with respect to the fourth quarter of 2014.

TRC standalone distributable cash flow for the fourth quarter of 2015 was $55 million, and dividends declared were $52 million. For the full year of 2015, TRC's standalone distributable cash flow was $214 million, compared to $125 million in 2014. As of January 31, TRC had $452 million in borrowings outstanding under its $670 million senior secured credit facility, and $15 million in cash, resulting in total liquidity of $233 million. The balance on TRC's term loan [B] was $160 million.

I want to provide some additional information related to the tax attributes of TRC's acquisition of TRP. Based on TRP's equity value and total debt on the date that the acquisition closed, we estimated a starting tax basis of approximately $7 billion. Some of that will be depreciated on a 15-year straight-line basis, and some on a more accelerated basis. The net reduction in taxable income means we do not expect to be a cash taxpayer for at least five years.

I also want to briefly cover some of the details related to our preferred plus warrant structure as published in an 8-K on Wednesday. We announced that Stonepeak has executed agreements to invest $500 million at closing, which is expected in mid-March. Quickly running over the structure, Stonepeak will receive 500,000 shares of newly-created series of 9.5% preferred stock that will pay quarterly dividends. At our option, Targa may pay quarterly dividends in additional preferred shares and warrants during the first two years after closing, a two-year [pick] option.

Additionally Stonepeak will receive approximately 7 million warrants with a strike price based on of VWAP of the 10-day trading -- of the 10 trading days prior to announcement, or $18.88. Stonepeak will also receive a second tranche of warrants, or approximately 3.4 million warrants with the strike price based on a 33% premium to the VWAP of the 10 trading days prior to announcement, or $25.11. The warrants are detachable but cannot be exercised for six months after closing. The warrants will also net settle at Targa's option for either cash or shares.

After the fifth year, Targa can redeem the preferred shares for cash at 110, and after the sixth year and beyond at 105. If the preferred shares have not been redeemed after 12 years, Stonepeak can convert into common shares, and Targa can also convert the preferred into common stock under certain conditions. From Targa's perspective, our base case assumption is that we will redeem the preferred shares between year 6 and year 12, which is another one of the attractive elements of this structure, as we believe that is a significant period time to redeem at a lower all-in cost of capital. With that, I will now turn the call back over to Joe Bob.

Thanks, Matt. I'm never going to live that down. That was my phone that rang just a second ago. After often being the one who reminds people to have their phones off.

Taking a step towards you all's questions, one of the most consistent questions that we've gotten from analysts and investors over the last few months, and certainly an important theme in the current environment, is related to counterparty credit exposure. From our early days as a start-up midstream company, we have always taken our counterparty credit exposure very seriously, and are always focused on understanding and managing the implications of each contract, going both directions.

To a significant extent, we benefit from a highly-diversified portfolio of customer positions across our multiple businesses, and across our multiple geographic areas. Our forecasting process takes into account the financial position of our counterparties, and we try to appropriately risk volumes and margins as their situation changes. We also monitor and manage our customer exposures on a customer-by-customer and contract-by-contract basis, and we always have. And in this environment, those normal processes are on high alert.

We try to not publicly discuss specific customers or customer contracts, but believe we are well-positioned to manage through risks associated with potential counterparty default or bankruptcy, and will continue to stress our forecasts with full consideration to credit risks and lower commodity price environments. Just as we constantly try to assess the volume implications of those price scenarios.

I understand your concern, and I believe that the best way to summarize our current situation is to state that separate from the volume and activity level uncertainties that we have already talked about, we do not currently believe that Targa has any significant unmitigated producer contract exposures, nor do we have any significant unmitigated fractionation contract exposures that we should highlight to our investors. We understand the concerns and the interest in the questions related to counterparty exposure, and hope that simple statement helps alleviate your Targa-specific concerns.

On our third-quarter earnings call in early November, I provided some preliminary collar on our expectations for field gathering and processing volumes in 2016 versus 2015. As prices have moved significantly lower since then, I think the easiest way to summarize our view of field G&P volumes today is to say that producer activity level uncertainties are even greater now, and that our expectations for 2016 versus 2015 have been tempered. We previously said that for 2016, we expected our overall field G&P volume growth to be flat to single digits versus 2015. In today's environment, I still believe that overall field G&P volumes will be positive for 2016 versus 2015, but the uncertainties associated with 2016 volumes are significant and could push us to flat or slightly negative.

Providing some additional detail on that summary statement. In the Permian, recent activity has created volume growth around our West Texas system in the Midland Basin, and our Versado system in the central basin platform and Delaware basin. To handle the growth in the West Texas system, and to provide some relief to that system which has been operated well over capacity for quite a while, the 200 million cubic feet per day Buffalo plant will be in service in the second quarter of 2016. We are forecasting growth still in 2016 for West Tex due to increased drilling efficiencies, improved well results despite the current commodity prices, and decreasing rig counts. We expect volumes in the Versado system to be slightly higher in 2016, driven by activity in the northern Delaware basin, and frankly driven by progress to date even as we look on uncertainties into the future. So across the Permian we expect average volumes to increase for 2016 over 2015, but the Permian basin rig count continues to decrease, and our view of the magnitude of the volume increase is lower relative to our last earnings call.

Moving to the Mid-Continent, we expect volume declines in North Texas, West OK and South OK to a greater extent than on our November call. Still, to some extent, price appreciation from today's level could result in SCOOP volumes in South OK surprising to the upside. In the Badlands, we expect natural gas volumes to increase for 2016 versus 2015, even at the current prices, and for crude to be at similar levels 2016 versus 2015. Both due to some continuing producer activity, and as Matt mentioned earlier, continued infrastructure build out to capture volumes from wells already producing on the Fort Berthold Indian reservation. In October of 2015, we announced a joint venture with Sanchez, and that agreement will result in some additional volumes in 2016 going to our Silver Oak facilities.

In conclusion, across our field gathering and processing system, based on the best information we have today, we believe that the expected volume increases in the Permian, South Texas and the Badlands will likely offset the declines in the Mid-Continent, but not to as great of an extent as we thought in November.

Downstream, as we have previously stated for LPG exports, we expect 2016 to average at least 5 million barrels per month of propane and butane exports. We're off to a good start in 2016, and I would like to mention how proud I am of the commercial and operational team that manages a flexible and competitively advantaged mix of handy midsize and VLGC services as well, as a competitively-advantaged mix of butane and propane cargoes. That benefits Targa and our customers.

I guess in closing, I want to reiterate that I am incredibly proud of our employees, and want to thank them for their efforts in 2015 and 2016. Their focus, dedication, and operational and commercial execution drove strong results in 2015, despite significant headwinds from commodity prices. That focus, dedication, and execution will continue to translate into results in 2016 and beyond. So with that, we will open it up to questions, and I will turn it back to you, operator. Thanks.

(Operator Instructions)

TJ Schultz, RBC Capital Markets.

I understand the commentary that you have bought some time to discuss dividend policy going forward. We can extrapolate there is some headroom on coverage if we assume flat dividends, and you certainly have other levers you can still pull. Has your view over the medium term evolved to a point where there is a specific dividend coverage level that you see that is most appropriate for the business, or is there level of coverage too low, that now you just don't want to operate at, and then would push you to change dividend policy? Anything further you can provide on stability of the current dividend in this commodity environment?

Thanks for the question, TJ. I would say that our thinking has not changed dramatically, and that we have time to listen to the markets. There are disparate views in the markets. Our equity and our debt are certainly dislocated in the markets, and that we don't have additional clarity to the extent that your question suggested.

Okay. Fair enough. You have a lot of levers on the cost side. How much more room is there on this lever in 2016, whether through OpEx or D&A? Just trying to gauge how hard you've already purchased this through the fourth-quarter results.

First of all I'm very proud of what's been pushed through, good term, in 2015. Smart, well-thought-out cost reductions, really across our Company. And using best practices across the multiple businesses to continue to drive, for example, operating cost reductions, savings on maintenance capital, without sacrificing safety or saving dollars that will cause us to spend more dollars later.

That continuous performance improvement. For example root cause analysis, or taking the best performance of the top quartile of those businesses and rolling it to the other businesses, is ongoing. Our operations team have stretch targets that they believe they will achieve for 2016. So yes, I think my comments said that we expect continued performance improvement in those areas. We expect continued improvement performance in those areas.

Just to add to that, I agree with Joe Bob on all of those fronts. There are some factors that are going to lead in the opposite direction to higher OpEx. So CBF Train 5 coming on, Buffalo plant, we have some additional facilities coming on. If you're looking at it in terms of run rate, you will have to increase for additional expansion at facilities coming online.

I will go so far as to say that with those additional operations coming on, and they are not insignificant, you may not see increases. Okay?

Okay got it. Just one more. Joe Bob, in your prepared remarks you want to the potential to benefit from several things to the upside, if and when things turn. You also mentioned some of the levers that you have to act on right now. One of those that was in both buckets was the potential from possible contract restructurings to your benefit. If you could expand on that opportunity, where you are maybe seeing the need to restructure now, or the potential to restructure some of the contracts, and how some of that impacts EBITDA?

Sure. First of all, I would expand on it by saying that is not really new for Targa. We sometimes get questions because of companies that are going from 0 to 180 on a portfolio change. Ours is more like one contract at a time across our businesses, and we see that as influential in today's environment. It has been part of the improvements we had in 2015, and we expect it to be part of the improvements we have in 2016.

It ensures that individual projects achieve an attractive return, or they are not done, for example. And it is on every commercial person's radar scope, but I don't have an EBITDA estimate for you. It will be one of the mitigating factors in part of the results that we deliver.

Okay, thank you.

Darren Horowitz, Raymond James.

Joe Bob I have a G&P question for you. You had mentioned the 30% or less forecast of 2016 margin, that obviously has a little bit more POP contract exposure. And I understand the commodity price sensitivities that you have previously detailed. If we were to back out the benefit from the fee-based projects that you have coming into service over the course of this year and just look at the base business, where do you want that fee-based profile to be exiting this year, and as you look to next year, upon some of those contract restructuring opportunities, how do you balance that fee-based component of cash flow versus the ability to participate in what you said a price upside potential scenario, should it occur.

I think the short answer to your question is that all of our investors would like to see that fee-based component go down, because commodity prices went up. But what we don't have is a magic dial of saying where do we want it to be. We are managing that in the context of the opportunities that have been presented to us over a multi-year path. The balancing is one opportunity at a time, not a magic formula that we can change from quarter to quarter.

Okay. And then my last question, with regard to counterparty risk, in your terms, you said that you don't have significant unmitigated contract exposure, and I'm just wondering if you could quantify the threshold either in EBITDA or revenue terms, that is, quote, significant by your definition.

Okay. First of all the traditional measure of counterparties on revenue terms is not terribly useful. We can provide those rankings, but it doesn't help when you think about EBITDA exposure, which is what we're trying to manage and you are interested in. The way I characterized it was reviewing it with our commercial leadership and our credit committee, one contract at a time. I do not see a significant one, meeting hitting the radar scope of a discussion with our investors, as being out there and unmitigated.

I understand other companies, and the issues that are being discussed and published. We don't have anything that comes close to those levels. So I'm not giving you a magic number. I am giving you the -- consistent with what we bring to these earning calls, consistent to what we bring to our investor presentations, which is a level of interest and significance and changes to expectations. There is not anything out there. Okay?

Thank you.

I should say there's not currently anything out there, because I just looked at a three days ago, and I know commodity prices are getting worse and that a lot of E&P companies are in trouble. We don't have a significant unmitigated position that I would feel should have been brought to this discussion.

Brandon Blossman, Tudor, Pickering, Holt & Co.

Start with something relatively easy. What is your objective here as we go through the bottom of this cycle, in terms of hedging and leaving some exposure to the upside for 2016 and 2017?

We have added, tracked quarter to quarter, we have added some hedges, but we really have not added much. Where we see rallies, or relative rallies anyway, of gas or crude we may layer on some additional hedges. We're not at this point looking to catch up to make up to our targeted exposures. If we can find pockets where it may make sense to hedge an NGL component, or maybe some additional gas or crude, we will take a look at that. Short of a significant rally in those commodity prices, I don't see us looking to make up our hedge position.

Fair enough. Any general estimates of where you are mark-to-market on that 40% hedge position for 2016?

That will be in the K that we file, you will see full details on the mark for assets and liabilities when we file that.

We got a question last call about, I think the it already zeroed in on an estimate. It is positive. No surprise it's positive whether we would take that off the table. That is unlikely to occur.

Okay. Fair enough. And then Joe Bob, I appreciate the need to parse words here, but purely conceptual not from a defensive perspective, needing to protect a balance sheet or provide incremental cushion, but dividend policy on a go forward basis, as it relates to where the equity is trading at, and what the market is telling you about their expectations with dividend policy, how do you thread that needle between giving cash out when the market doesn't, at this point in time, appreciate that cash in terms of dividend?

I understand your question. I think it's interesting describing threading the needle of what the market is telling me. There are probably people on this call who if I polled them scream -- cut your dividend to zero or cut it to X; and other people on the call who would scream -- you should say you would never cut your dividend. That's not much of a needle, that's a giant gap in market perceptions. We hear them both, constantly, as I'm sure other midstream companies are hearing.

We are trying to listen to the market, the market on the margin. Right now the market on the margin is irrational about Targa's equity pricing in my opinion, and with cushion, we have time to see how things are sorting out without making rash moves. I think that's a luxury. I'm not trying to parse words, I'm trying to tell you exactly how I'm thinking about it.

Understood, and actually appreciate that color, Joe Bob. That's all for me.

Sunil Sibal, Seaport Global Securities.

Congrats on the really strong quarter. A couple of questions for me. First off, starting off with some of the areas which you mentioned seeing a lot of weakness in terms of producer activity. I was curious if you had any thoughts about, around industry consolidation in some of those areas, and any opportunities you see either way?

No, I ran into a friend of mine at breakfast. Why am I answering it this way? He's from the oil field services industry, and talks about this as the time the oil field services industry will shake out, and the opportunities will occur before the upturn. Having been through multiple cycles, we believe there are opportunities in downturns, even without trying to pick a particular time, and consolidation is naturally occurring now, without even transactions.

Volumes are moving to the strong from the week. You can see on the E&P side, struggling companies, their ownership will change. In the midstream side, ownership of assets and companies will change. We have said before that we are mostly looking around our strong asset footprint, and that is the best place for us to look for opportunities.

It may just be an opportunity to consolidate a volume from someone who can't service it. It may be a minor asset acquisition. It may be a deal with another midstream provider to more efficiently do something. Those are the kind of opportunities that fall in that bucket you described as consolidation, and we will keep an eye out for them. Part of our financial flexibility, part of the benefit of that financial flexibility, is to try not to turn down high-return opportunities.

That's helpful. If you could talk a little bit about the Stonepeak transaction, how it came about, was that something you were looking at for some time? How did it really precipitate it?

We have been talking about preferreds and looking at that as a tool and our financing toolkit back to the Saddle Butte acquisition. It has been years we have been considering whether it made sense to do a preferred or convertible preferred. As industry conditions worsened over the course of last year, as Joe Bob said earlier, I think it was early September, we put in our presentations with where NGLS common unit price was trading, we were looking at alternate financing. So that included preferreds, convertible preferreds, potential asset sales, and we executed on the retail preferred offering shortly thereafter of $125 million.

Really since we said that at the conference in early September we have received a number of term sheets, whether they are asset-level preferreds up to the corporate level, with it's TRP or TRC, we had a lot of incoming and a lot of term sheets about potential structures and ideas. So we have been working that really pretty hard all through last fall.

The transaction with Stonepeak came together relatively quickly over the 2016 period, but this is something we have been working on for months, and the structure and exact terms, of course, change as you're going to the process. This is -- something general like this we been working on for quite a period of time.

Okay. That's helpful. And then a couple of bookkeeping questions for me. In terms of your OpEx, I was wondering if you can provide some sensitivity of that OpEx to gas prices or even NGL prices?

When I'm talking about OpEx savings, our primary focus has been on the controllable OpEx savings. Much of operating costs associated with natural gas, or in the case of electric power-driven facilities, much of that is passed on to our customers. We keep an eye on it, and we manage it to the greatest extent we can, but all of the cost savings descriptions that I gave earlier in my comments were not focused on pass-through fuel type savings.

Got it. And lastly, how much was the cash interest expense this quarter?

The interest expense line, you will see, looks relatively low. If you look through some of the details there, we had a $30 million non-cash interest income, which was an offset to the interest expense. That was due to a change in the redemption value of our JV partnership for the West Oak and West Texas assets that are in a JV partnership, and so the redemption value change flows to interest expense. There's an additional $30 million of interest non-cash interest income in that interest expense line.

Got it. Thanks, and congrats once again.

Chris Sighinolfi, Jefferies.

Thanks for the added color this morning. Just a couple bookkeeping questions. Matt, with the preferred offering, you have the option to take those distributions in the first couple of years? And I was just curious what we should assume, or if you had made a formal assumption in your modeling on what you were going to do?

No. We have not determined whether we're going to pay in cash or pick. We will be determining that in our normal quarterly distribution. I guess now dividend declaration, so that will be a decision that will be made by management and the Board at that time.

Okay. And then I apologize for my ignorance on this, but what does the Board observer mean? Scott being added to your Board but you had mentioned in the release and today in the call as an observer. I was curious what the distinction was. Is he not sitting on any committees, does he have a voting position? Could you just help clarify that.

I'm happy to help clarify that. The primary distinction between an observer and another board member as we will operationalize it, is just his official ability to vote. We have had a board observer in the past at TRC. It was a Merrill Lynch private equity Board observer, when they joined on the Dynegy Midstream acquisition through interest sold by Warburg Pincus. And without mentioning that person's name, they didn't just sit and observe on the Board, they contributed and brought their experience and industry understanding, and that's what we expect Scott to do, as well. When you have Board vote, he does not officially vote and he would not be officially be a part of creating a quorum to vote, and he will not be at assigned to our compensation or audit committee, and would not qualify to serve on those.

Okay. Thanks a lot. That's what I had suspected, but I appreciate the clarity. Matt, I'm sorry if I missed this, you had said it in your prepared remarks, but typically you give the hedge percentage on the products.

It was 40% and 24% gas and crude and then NGLs I believe, was 20% in 2016, and 10% in 2017.

Okay. And did you say at what levels?

No, that will be in our K.

And then finally, I just wanted to quickly go back to Joe Bob, so I could understand if I'm interpreting what you have said correctly. Obviously, with the roll-in, the cash savings associated with the roll-in and then the preferred offering, you have an incredible amount of headroom, certainly relative to much of your peer group on the compliance leverage covenants. Significant amount of current liquidity, not a terrible amount in terms of near-time growth CapEx that you have to do. And then a somewhat schizophrenic market view as to what you should do with your dividend. Am I just to interpret that flexibility is going to afford you an ability to wait and make a major decision over time, as conditions either improve or do not improve?

There was a first part of your statement that was talking about the context, I think you nailed it. I'm not trying to put new words in your mouth. I believe that the measured response, the thoughtful response over time, trying to weigh the factors we see today and the factors we will be seeing tomorrow, is the right way to interpret what I was saying.

It is a luxury to have that space. To not be focused into a rash decision, and that is not poking at any companies that were hanging on, or being forced into those rash decisions. That's not where Targa is, we have the luxury of being thoughtful about how we balance, balance sheet strength, which we have and intend to keep, and how we are serving our shareholders over time with dividend policy, as you put it.

Okay. Thanks so much for the time this morning. I really appreciate it.

Helen Ryoo, Barclays.

A couple quick questions.

Helen, your phone broke up a lot. Can you start over?

Can you hear me better?

That's better.

Great, thank you. On your CapEx comment just to clarify, the $175 million you referenced, does that imply there is about $75 million of wiggle room to reduce your CapEx budget for the year? And also, on that $175 million, is that mostly Badlands related and what is the lead time for the project in that $175 million number?

Let's start over a bit. What Matt pointed to was other projects currently showing at about $250 million, and our prediction that we would spend at least $175 million. First of all, any dollar we spend in that category is an attractive return, and almost all will be immediate 2016 cash flow. So as an investor, you want dollars being spent there. I just want to make sure that is clear to everybody.

We're not going to be spending dollars in that category that aren't well spent, and that investors do not want us to spend. We have luxury in that category of looking and being careful about the dollars we spend. That probably includes the category of unidentified projects, if something comes up, it will need to be very attractive return compared to the funds that are required to support it and quick cash flow is better than delayed cash flow.

What Matt said was the largest piece of projects was from the Badlands, and then he used that as an example of immediate cash and attractive return. And then said that other expenditures in that category would be similar. Does that help?

Yes, that does. Just to clarify. $250 million is a sum of the four projects that were already identified, that will --

No ma'am.

Sorry, so that's the additional -- $250 million is outside of that number.

$275 million is the four projects. $250 million, it's just coincident that they're about the same magnitude. $250 million is our estimate for a set of identified projects from a few months ago. $175 million or more is the estimate of how much of that we will spend in 2016.

Got it. That is very helpful. The Noble project, it is not coming online until 2017, but you are going to get that cash flowing starting 2016?

That's not right either. The Noble project is expected to come on the first quarter of 2018. We will get cash flow in 2016 as a function of what has been a couple of renegotiations around the terms of that project or projects. We said from the beginning that we would not be economically disadvantaged by essentially a one-year option, as Noble reevaluated exactly what they wanted to do. Payments in 2016 are a function of that.

Okay. That is helpful. Going back to your comments on counterparty risk, just curious, you did have a little bit a Quicksilver exposure and it seems like that contract got rejected pretty early in their bankruptcy process. Just curious, was there anything special about that contract that made it vulnerable or should we think a lot of these transmission-type projects or contracts are typically more vulnerable in that situation, if you could provide your view.

You mentioned a Quicksilver contract. The most interesting thing about that would be how it was discussed in the market, despite confidentiality agreements. I don't intend to break it. Apparently others don't have a problem with that.

What I can say, is what I told you previously, there is nothing significant that I need to talk to you about. And if that particular contract were included, I was still say there is nothing significant I need to talk to you about. That's really the best I can do with that one right now. I would certainly not characterize any relationship I might have with that company or any renegotiation around that contract as being at all typical, or are having duplicates in my fractionation contract portfolio.

Okay. And lastly, Joe Bob, on your comment about the $130 million of negative effect with the commodity downturn after Atlas acquisition. Does that take into account the hedge protection that came with Atlas? Or is that without that number?

First of all, it was only looking at performance relative to a single forecast, which was the official Board-approved plan. And yes, it was after taking into effect hedges.

Okay. Great. Thank you very much.

Jeff Birnbaum, Wunderlich.

I got kicked off the call for a minute, so I apologize if I duplicate any questions. Matt, did you mention it there were any deficiency payments that you received in the quarter? If not, were there?

No, we did not give a breakout. We typically do receive some deficiency payments on our take-or-pay contents, whether it be fractionation or the G&P side. We did not provide that detail, we didn't feel it was significant enough to give that color. So there is some seasonality to our logistics business, where we get some of those payments in Q4, but we didn't give detail on that at this time.

Okay. Thank you. And then just coming back to LPG exports. Obviously, you've seen some good strength in the fourth quarter. It seems like the first quarter to date has been strong. Not given your comment about 5 million barrels a month being a good number to use this year, relative to those more recent results, can you talk a bit about how you see that being driven either by seasonality or the first half relative to the back half? And I know you love talking about this, but have you added contracted barrels since you last updated the market on that, and is that something you can quantify for us?

I looked across the table and Scott Pryor, who runs that business, smiled at me. He doesn't have anything long enough to hit me with, but he can find me. Our 5 million barrel per month average for 2016, we believe, is a good number for you. We gave that number actually some time ago. We said that 2016 was off to a good start.

There are some published reports where people look at ships leaving docks and that sort of thing, and I guess we are saying yes, those published reports are probably right, and our 2016 has gotten off to a strong start. We haven't had a whole lot of annual performance from our docks. It is relatively new business. There is a little bit of seasonal effect the late first quarter going into second quarter, as a function of global seasonal usage of waterborne LPGs, and impacts some things on the margin.

You can see it in the last year's performance. We halfway expect it in this year's performance and I think that is why Matt or I may have mentioned some seasonality. On average, for 2016, we expect 5 million barrels per month. I do not expect 5 million barrels every month. Does that help at all?

Yes, Joe Bob. Thank you. It does help. As we think about the current rate and what you get past that seasonality, the question is do you expect a normal impact from seasonality, or is something greater this year that is taking it to the -- when you call the 5 million barrel a month an accurate -- a conservative number or a best guess number?

I think you're parsing my statements more than we parsed our statements.

Okay.

I think 5 million barrels a month is good number for you. I did say towards the end of last year I felt better about that 5 million barrel a month estimate than when we first put it out there. I feel at least that good. Does that help?

It does. Thank you.

Eric McCarthy, Citadel.

You touched on ethane recovery in your prepared remarks earlier. Can you quantify or approximate total ethane rejection across the system occurring?

How much rejection is occurring?

Yes.

I don't have that number for you. I would characterize it as there is still significant amount of methane rejection occurring among gathering and processing facilities, Targa's and others, who have come into our systems, where they can most economically do so. You should assume that all participants are making economic decisions every week or every day about what they should reject or recover, and that most of those parties are thinking about what some costs they might have in T&F when they make those decisions. We are a long way from significant ethane extraction relative to available economic ethane rejection, if that's helpful for you directionally.

Directionally, some of your peers talk about how big the opportunity is over the next three years? If I think back to how much ethane Atlas was rejecting, and compare that to your system, of if I take the approximately 250,000 barrels a day of NGLs being produced, would we say it's 50%, 75% ethane rejection, because that's along the order of 50,000 or 60,000 barrels a day that are being rejected?

I'm not providing a target number for you. I have a question for you. When people are quantifying that, what price do you think they're using for ethane?

I would imagine by 2018, 2019 if there's big demand. This going to be some uplift off of residual fuel value, right?

I think you've definitely gotten to the key. You have to incent the ethane to be extracted, and if the ethane is being incented to be extracted, you've got an increase of ethane prices. Ethane won't go up by itself. It will probably be a propane response, propane and ethane would probably go together.

The potential for that is a combination of volumes for fractionation and volumes and price for other NGLs. And yes, that's an upside potential for Targa, but there are a lot of variables to assume, to come up with what is that dollar potential. It doesn't make sense for Targa to pick one volume and one price and one outcome in 2018, to try to quantify for you right now. I don't think.

Okay. And then on the Bakken, you touched on the build out of that system. Do you have an approximate number of the current volumes that are being truck gathered, either on your acreage dedication or nearby?

It's thousands of barrels. Tens of thousands of barrels.

Okay. When you talk about building that system out further, is that the opportunity to capture those volumes currently being trucked, or is to expand to the wells that are scheduled to be completed over the course of the year?

What Matt was characterizing relative to capital investment on the Badlands is primarily additional infrastructure on the Indian reservation, where we have been working for some time to capture both gas volumes being flared and oil volumes being trucked.

Okay.

And what I think you also heard, and this is part of the equation, is that we still expected gas to be up 2016 versus 2015 in the Badlands, and that all factors including well declines, we expected oil to be similar to 2016 versus 2015, at our current view of activity levels.

Okay. That's it for me. Thank you.

At this time I'm showing no further questions. I would like to turn the call back over to Mr. Joe Bob Perkins for closing remarks.

Thanks, operator. To the extent anyone has any follow-up questions, feel free to contact Jen, Matt, or any of us. Thank you again for your time today and your interest, and I look forward to speaking with you again soon.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may all disconnect. Everyone have a great day.