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Targa Resources’ (TRGP) CEO Joe Bob Perkins on Q4 2015 Results – Earnings Call Transcript

Operator Good day ladies and gentlemen, and welcome to the Targa Resources Fourth Quarter and Full Year 2015 Earnings Webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder this conference is being recorded. I would now like to introduce you host for today’s conference, Ms. Jennifer Kneale. Ma’am, you may begin. Jennifer Kneale Thank you, Laura. I’d 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’d like to mention that Targa Resources Corp., TRC or the company and Targa Resources Partners LP, Targa Resources Partners or the partnership have published the joint earnings release which is available on our website at www.targaresources.com. We’ll also be posting an investor presentation on the website later today. I’d also like to remind you that on February 17, Targa Resources Corp posted its acquisition of all 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 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, 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. Joe Bob Perkins Thanks, Jen. Welcome and thanks to everyone for participating. Before we turn to the Targa’s results, I’d 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. But overwhelming the 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 as 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, risk from lower prices, risk 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’ll try to address each of these topics related to Targa in some detail during the call. And we’ll try to provide you with color on our views of our risks, mitigation, 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 rd , 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’ve provided current EBITDA sensitivities for NGOs, 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 conclusion should be that Targa has financial flexibility across a wide range of potential scenarios. Also Targa is the 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 affiliate 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 are 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 have and we announced about six months ago that we would seek alternatives to public common equity funding. The preferred pace in 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 a presentation in early September that we were going to find attractive funding sources other than public equity and we patiently work to develop an attractive addition to Targa’s capital structure. With this preferred equity we are not trying to solve for any one specific variable or achieve any one specific metric instead consistent with what’s been going at Targa over the last year and a half and throughout the history of Targa and we identify a capital market opportunity or some other opportunity to do something to strengthen Targa for the future we have. In this case we indentified 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 retailer 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 are significant uncertainty in the market, but one thing is certain Targa is blessed with 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 a long term shareholder value regardless of the environment. We are also very excited to have Stonepeak as an important financial partner of ours. And we welcome Scott Hobbs as an observatory 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 the pro forma basis importantly reduces TRP’s year end compliance leverage ratio to 3.6x 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 in the placement of the debt. At TRC we have about $670 million of revolver, about a $160 million of term loan deal. At TRP we’ve a $1.6 billion revolver, a $225 million accounts receivable facility and publicly traded notes. There is a compliance covenant of 5.5x at TRP, but there is no other meaningful covenant or constraints on TRP leverage, TRC leverage or consolidated leverage. Pro forma for the $500 million preferred TRP compliance leverage is 3.6x versus that 5.5x compliance covenant. My simple math that means to me we have almost two turns of cushions. And with our long term often repeated target range for compliance leverage having been 3x to 4x we believe that Targa is currently in a very strong balance sheet position from a Targa historical perspective and probably relatively 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 peruse 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 forecast and I can promise you that the decision making associated with our company is fluid and evolving always seeking to outperform our internal forecast and expectations. We will continue to focus on taking the right forward looking steps for Targa, trying to improve on all controllable factors or 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 phase of uncertain prices, uncertain activity levels and related uncertain volumes perhaps may even more uncertain by oil prices breaking $30 several times over the last month and a half, you will now 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 and a 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 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 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 a 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 billion $191 million. A 23% increase versus 2014. I want t o 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 prices assumptions that we used for our 2015 board approved plan, our adjusted EBITDA was negatively impacted by about $130 million based on price alone. Meaning we were about a $130 million in the whole to solely for price variance. But our final adjusted EBITDA of $1 billion $191 million beat the 2015 board approved plan by about $25 million, the biggest compensating drivers for VAT mitigation, we reduced OpEx across the asset footprint, improved contract margins, lower G&A and better than expected downstream LPG export and storage performance. I am 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. Very important work in 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 acquisition of TRP under the price sensitivity scenario presented at announcement on November 3, then published again on December 3, we showed an estimated dividend growth of 10% of 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 forecast are lower and even more uncertain and equity and debt market volatility and pressures have increased. So what does that mean for Targa? Means that we will continue to make decisions the way 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 didn’t make sense to us or our board. Similarly, making a rash decision to meaningfully change our quarterly dividend didn’t feel appropriate to us or board. We have many levers available to us as we think about our ability to execute in 2016 at market remains challenged, levers such as continued cost savings from OpEx, CapEx and G&A reductions. Pursuing identified opportunities to enhance EBITDA to improve volumes, contracts, high return in capital projects etcetera. Pursuing not yet identified opportunities to enhance EBITDA through similar cost savings or commercial actions. Consideration of assets sales or asset level joint ventures was 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 results 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 were thinking about managing target in the current environment. I’ll now turn the call over to Matt. Matthew Meloy Thanks, Joe Bob. I’d 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’s nothing fusion about the goodwill issue mentioned in our press release from February 9. As discussed in that release and quantified today, the partnership identified the material weakness in the control related to its review of the purchase accounting calculations used to estimate the preliminary fair value. As of the accusation date of the assets and liabilities acquired in the ATLS Merger. Goodwill at the merger date has been restated and we subsequently recognize 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 the 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 a 110 million of maintenance CapEx. Turning to the segment level of summarized fourth quarter’s performance on a year-over-year based is starting with our downstream business. Fourth quarter 2015 logistics and marketing operating margin was 15% lower than the same quarter last year driven a lower fractionation in LPG export margin. LPG export margins were down 15% from the fourth quarter of 2014, when we benefitted from record volumes. On our third quarter earnings call, we mentioned that we saw, we could continue to benefit from increased ship availability, growing waterborne LPG market, and globally competitive [indiscernible] prices with 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 today, 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 impact on producer and processing plant operation, as well as some lower customer volume and small amount of contract roll out. We have received questions over the last several months related to frac contract expiration. So, want to provide some additional color. Over the next three years, less than 5% of Targa’s frac contract expire in 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 pricing. 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 in that volume was due to the inclusion of TPL volume in West Texas, South Texas, South Oak and West Oak, and increases in volumes at SAOU, the Badlands, and Versado. At Sand Hills, volumes were essentially flat, given the system is basically full and we continue to move volume from Sand Hills 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 decrease to a 109,000 barrels per day in the fourth quarter, a 6% decrease versus same time period last year, primarily as a result of several produce for customers, shutting in existing production to frac new wells late in the fourth quarter of 2015. For the segment, commodity prices were 45% lower, 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 that on a debt compliance basis, which provides us adjusted EBITDA credit for material growth project 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 that to EBITDA, versus a compliance covenant of 5.5. Our fee based operating margins was 76% in the fourth quarter of 2015, and we had 74% of margins and fee-based operations for the full-year 2015. For 2016, we estimate more than 70% of fee-based operating margins. For the non-fee based operating margins, relative to our current equity volumes from Field Gathering and Processing, we estimate that we have had approximately 40% of 2016 and 20% 2017 for natural gas volumes, approximately 40% for 2016 and 20% for 2017 of common state volume 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 in 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 projects. CBF Train 5, the Noble Group, and condensate splitter, the Buffalo plant in West Texas, and the joint venture with Sanchez and 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 a 175 million of this amount. A larger part of that capital is expected to be spend in the Badlands where we will continue to build out our infrastructure and where as you have heard from us many times before, we have been delayed by right away on the Fort Berthold Indian Reservation. The Badlands growth capital will add infrastructure to net 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 spend in this category will generally only be spend if the returns are significantly in excess of our funding cost and we’ll likely generate near term cash flow. Next, I’ll make a few brief remarks about the result of Targa Resources Corp. January 19, TRC declared fourth quarter cash dividend at $0.91 per common share at $3.64 per common share on the annualized basis, representing in approximately 17% increase over the annualized rate pay with respect to the fourth quarter of 2014. TRC standalone distributable cash flow for the fourth quarter 2015 was 55 million and dividends acquired were 52 million. For the full-year 2015, TRC standalone distributable cash flow was 214 million compared to a 125 million in 2014. As of January 31 st , TRC had 452 million in borrowings outstanding under a 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 fee was a 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 of 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 tax full income means, we do not expect to be a cash tax payer for at least five years. I also want to briefly cover some of the details related to our preferred plus one structure as published in an 8-k on Wednesday. We announced at Stonepeak because it’s 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 dividend. At our option, Targa may pay quarterly dividend 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 the view 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 of approximately 3.4 million warrants with a strike price based on a 33% premium to the [indiscernible] 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 as 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 assumptions that we were redeemed the preferred share between year six and year 12, which is another one of the attractive elements of this structure as we believe that is a significant period of time to redeem at a lower all in cost of capital. With that, I’ll now turn the call back over to Joe Bob. Joe Bob Perkins Thanks, Matt. Okay. 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 your asked questions, one of the most consistent questions that we’ve got from analysts and investor is related to counter party credit exposure. From my early days, is a start-up midstream company, we’ve always taken our counter party credit exposure very seriously. And 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 counter parties 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 in 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 risk associated with potential counter party default or bankruptcy and will continue to stress our forecast with full consideration to credit risk 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 when certainties that we’ve 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 counter party exposure and hope that that simple statement helps alleviate your Targa specific concerns. On our third quarter earnings preliminary color, 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 a capacity for quite a while. The 200 million cubic feet per day Buffalo plants will be in service in the second quarter of 2016. We are forecasting growth, still in 2016 for WestTX due to increased drilling efficiencies, improved well results despite the current commodity prices and decreasing rig counts. We expect volumes in the Versado’s 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 decline in North Texas, West Oak and South Oak, 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 Oak, 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 buildout to capture volumes from wells already producing on the Fort Berthold Indian Reservation. In October 2015, we announced the joint venture with Sanchez and that agreement will result in some additional volumes in 2016, going to our Silver Oak facilities. So, 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 were 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 advantage mix of handy mid-sized and VLCC services, as well as the competitively advantage 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 focused dedication and execution will continue to translate into results in 2016 and beyond. So, with that, we’ll open it up to questions, and I’ll turn it back to you operator. Question-and-Answer Session Operator Thank you. [Operator Instructions] Our first question comes from TJ Schultz from RBC Capital Markets. Your line is open. Joe Bob Perkins Good morning, TJ. TJ Schultz Good morning. Matthew Meloy Good morning. TJ Schultz I understand the commentary that you’ve bought some time to discuss dividend policy going forward. We can extrapolate, there’s some headroom on coverage, if we assume flat dividends and you certainly have other levers you can still pull. So, how’s your view over the medium term of walls to point where there is a specific dividend coverage level that you see as most appropriate for the business or is there a level of coverage too low that now you just don’t want to operate that and then would push you to change dividend policy. Just anything further you can provide on stability of the current dividend in this commodity environment? Joe Bob Perkins Thanks for the question, TJ. I would say that us thinking has not changed dramatically, and that we have time to listen to the markets. There are disparate views in the markets. Our equity in our debt are certainly dislocated in the markets. And that we don’t have additional clarity to the extent that your question suggests. TJ Schultz 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 G&A, just trying to gauge how hard you’ve already pushed this through the fourth quarter result? Joe Bob Perkins 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 companies, 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 cost us to spin more dollars later. That continuous performance improvement, for example, root cause analysis are taking the best performance of the top [indiscernible] of those business and rolling it to the other businesses is ongoing. Operations team has stretched targets that they believe they will achieve for 2016 [Audio Gap] continued performance improvement in those areas. We expect continued performance improvement in those areas. Matthew Meloy And just to add to that, I agree with Joe Bob in all those front. There are some factors that are going to lead in the opposite direction to higher OpEx, right. The CBF Train 5 coming on Buffalo point. We have some additional facilities coming on. So, if you’re looking at in terms of run rate, you’re going to have to increase for additional expansion at facilities coming online. Joe Bob Perkins And now, I’ll go so far as to say, now with those additional operations coming out and they’re not insignificant, you may not see increases, right, yes, okay. TJ Schultz Okay, got it. Just one more. Joe Bob, in your prepared remarks, you did walk through the potential the benefit from several things to the upside if and when things turn and you also mentioned some of the levers that you have to act on right now. And one of those that was kind of in both buckets was the potential from possible contract restructurings to your benefit. If you can expand on that opportunity where you may be seeing some need to restructure now or the potential to restructure some of the contracts and how some of that impacts EBITDA? Joe Bob Perkins Sure. First of all, I’d expand on it by saying that’s not really new for Targa. And we sometimes get questions because of companies that are sort of going from zero 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’s been part of the improvements we had in 2015 and we expect it to be part of the improvements we have in 2016. It insures that individual projects achieve an attractive return or they’re not done for example. And it is on every commercial person’s right on scope, but they don’t have any EBITDA estimate for you. It will be one of the mitigating factors and part of the results that we deliver. TJ Schultz Okay, thank you. Operator And our next question comes from Darren Horowitz from Raymond James. Your line is open. Darren Horowitz Joe Bob, I’ve got 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 previously detailed. If we were to back out the benefit of the fee-based projects that you guys have coming to 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? Joe Bob Perkins I think the short answer to your question is that all of our investor 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’re managing at in the context of the opportunities that have been presented to us over a multiyear of path. The balancing is sort of one opportunity at a time, not a magic formula that we can change from quarter-to-quarter. Darren Horowitz Okay. And then my last question. Just with regard to counterparty risk. In near 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 o revenue terms that is co-significant by your definition? Joe Bob Perkins Okay. First of all, the traditional measure of counter parties 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. Way I characterized it was reviewing it with our commercial leadership in our credit committee, one contract at a time, I don’t see a significant one, meaning 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’m giving you that consistent with what we bring to these earnings calls consistent to what we bring to our investor presentations, which is a level of interest in significance and changes to expectations. There is not anything out there. Okay? Darren Horowitz Thank you. Joe Bob Perkins I should say there is not currently anything out there, because I just looked at it three days ago. Okay. And I know commodity prices are getting worse and that a lot of EMP companies are in trouble. But we don’t have a significant unmitigated position that I would feel should have been brought to this discussion. Operator And our next question comes from Brandon Blossman from Tudor, Pickering, Holt and Company. Your line is open. Brandon Blossman Good morning, guys. Joe Bob Perkins Hi, good morning. Brandon Blossman Let me start with something positively easy. What’s the objective here as we go through the bottom of the cycle in terms of hedging and leading some exposure to the upside for ’16 and ’17? Matthew Meloy Yes. We have had as it going to track quarter-to-quarter we’ve added some hedges, but we really have not added much, where we see rally and your relative rally is anyway 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. So, we can find pockets where it may make sense to hedge an NGL component or maybe some additional gas or crude. We’ll take a look at that so sort of a significant rally in those commodity prices, I don’t see us looking to make up our head position. Brandon Blossman That’s fair enough and any general estimates down where your mark-to-market on 40% hedge positioned for 2016 you are? Matthew Meloy That will be the case that we file you will see full details on the mark for assets and liabilities when we file that. Joe Bob Perkins we got a question last call about make that already see road down on a estimate of how, it’s positive no surprise it’s positive whether we would take that off the table that’s unlikely to occur. Brandon Blossman Okay fair enough. And then Joe Bob, I appreciate the need to — here but just purely conceptual not from a defensive perspective needing to reflect the balance sheet or providing amount of cushion at dividend policy on a go forward basis as it relates to where the equity is trading at and what the markets telling you about their expectations of the dividend policy how do you spread that needle between giving cash out when the market doesn’t at this point in time appreciate that cash in terms of dividend? Joe Bob Perkins I understand your question, I think it’s interesting describing threading the needle of what the market, I pulled them with strain, cut your dividend to zero or cut it to x and other people on the call 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 and we hear them both constantly as I am sure other midstream companies are hearing. So we are trying to listen to the market, the market on the margin right now the market on the margins 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 am not trying to parse words I am trying to tell you exactly how I am thinking about it. Brandon Blossman Okay understood and actually appreciate that color Joe Bob that’s all from me. Joe Bob Perkins Thank you. Operator And our next question comes from Sunil Sibal with Seaport Global Securities. Your line is open. Sunil Sibal Hi good morning guys and congrats on nearly a strong quarter. Joe Bob Perkins Thanks good morning. Sunil Sibal Couple of questions from me, first off starting off with some of the areas which I mentioned seeing lot of weakness in terms of producer activity, I was kind of curious if you have any thoughts about around industry consolidation in some of those areas any opportunities you see either way? Joe Bob Perkins No I ran into a friend of mine at breakfast, why am I answering this way he is from the oil field services industry and talks about this is the time to 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 the particular time and consolidation is naturally occurring now without even transactions. Volumes are moving to the strong from the weak. You can see on the MP side struggling companies there were ownership will change in the midstream side ownership of assets in companies will change. We have said before that we are mostly looking our round, our strong asset footprint that’s the best place for us to look for opportunities. That may just be an opportunity to consolidate a volume from someone who can’t service it. It maybe a minor asset acquisition, it maybe a deal with another midstream provider to more efficiently do something those are the kind of opportunities that fall in that bucket you described this consolidation and we will keep an eye out for and part of our financial flexibility, part of the benefit of that financial flexibility is try not to turn down high return opportunities. Sunil Sibal Okay that’s helpful and then if you could talk a little bit about the Stonepeak transaction, how it kind of came about was that something again you are looking at for some time and how it really going to precipitated? Matthew Meloy Yes sure. We have been talking about preferred and looking at about is kind of a tool in our financing toolkit back, it’s the acquisition so that’s been years we have been considering whether it makes sense to do a preferred or convertible preferred. As industry conditions worsen over the course of last year as Joe Bob said earlier, I think it was early September we putting our presentation with NGLS common unit price frustrating, we were looking at alternate financing. And that included preferred, convertible preferred, potential asset sales and we executed on retail preferred offering shortly thereafter of $125 million. Really since we said that at the conference in early September we received a number of term sheets whether they are assets level preferred up to the corporate level whether 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 and the transaction with Stonepeak came together relatively quickly over in 2016 period but we have been, this is something we have been working on for months and the structure and exact terms of course change as you are going through the process but this is something general like this we have been working on for quite a period of time. Sunil Sibal Okay that’s helpful. And then couple of bookkeeping questions from me, in terms of your OpEx, I was wondering if you could provide some sensitivity of that OpEx to gas prices or even NGL prices? Joe Bob Perkins When I am talking about OpEx savings, our primary focus has been on the controllable OpEx savings much of operating cost associated with natural gas or in the case of electric power driven facilities, much of that is passed onto our customers. We keep an eye on it, we manage it to the greatest extent we can but all of the cost savings descriptions that I gave earlier in my comments we are not focused on pass through fuel type saves. Sunil Sibal Okay got it. And then, lastly how much was the cash interest expense this quarter? Matthew Meloy Yes, I think we are getting to, it looks that interest expense line you will see it 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 and that was due to change in the redemption value of our JV partnership for the West Oak and West Texas assets they are in a JV partnership and so there were redemption value change flows to interest expense so there is additional $30 million of non-cash interest income in that line. Sunil Sibal Okay got it, thanks guys and congrats once again. Matthew Meloy Okay thank you. Operator Our next question comes from Chris Sighinolfi with Jefferies. Your line is now open. Chris Sighinolfi Good morning Joe Bob. Joe Bob Perkins Good morning Chris. Chris Sighinolfi Thanks for the added colors. 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’re going to do? Matthew Meloy No, we have not determined whether we are going to pay in cash or pick, we will determining that in our normal quarterly distribution and I guess now dividend declaration so that will be a decision made by management and the board at that time. Chris Sighinolfi Okay. And then, I apologize from my events on this, but what does the board observer mean, what I mean Scott being added to your board but you have mentioned in the release and then today on the call as an observer and I was just curious what the distinction was, as he is not sitting on a committee that he have a voting position could you just help clarify that? Joe Bob Perkins Yes, I am happy to help clarify that the primary distinction between an observer and other board member as we will operationalize it, is just official ability to vote. We’ve had a board observer in the past at TRC it was a Merrill Lynch private equity a board observer when they joined on the midstream acquisition through interest sold by over thinkers and without mentioning that person’s name they did just sit an observer 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 a board vote he doesn’t officially vote and he would not be officially part of creating a quorum to vote and he will not be assigned to our compensation or audit committee, would not qualify to serve on this. Chris Sighinolfi Okay, thanks a lot. Kind of what I expected but appreciate the clarity. And then Matt, I am sorry if I missed this if you had said it in your prepared remarks, but I think typically you gave a hedge percentage on the products? Matthew Meloy Yes that is 40 and 20 for gas and 15% and 10% 2017. Chris Sighinolfi Okay and do you did you say at what levels. Matthew Meloy No that will be in our K when we file. Chris Sighinolfi Okay. And then finally, and I just wanted to quickly go back to Joe Bob so I could understand if I am 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 head room 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 the near term growth CapEx that’s you have to do. And then, somewhat schizophrenic market view as to what you should do with your dividend and so am I just to interpret that flexibility is going to be forward you an ability to sort of wait and making major decisions overtime as conditions either improve or do not improve? Joe Bob Perkins There was the first part of your statement that was talking about the context I think you nailed it. And I am not trying to put new words in your mouth, I believe that the measured response that’s thoughtful response overtime 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. And it is a luxury to have that space to not be forced into a rash decision and that’s not poking at you, companies that were hanging on or being forced into those rash decisions that’s not where target is. We have the luxury of being thoughtful about how we balance sheet strengthen which we have and intend to keep and how we are serving our shareholders over time with dividend policy if you put it. Chris Sighinolfi Okay. Thanks so much for the time this morning, I really appreciate. Joe Bob Perkins Thanks a lot. Matthew Meloy Okay thanks. Operator Our next question comes from Helen Ryoo from Barclays, your line is open. Helen Ryoo Thank you, good morning. I have just a couple of questions when you talk about the… Joe Bob Perkins Your phone broke up a lot, can you start over. Helen Ryoo Sure, sure. Could you hear me better? Joe Bob Perkins That’s better. Helen Ryoo Okay great. Thank you. So yes, on your CapEx comment just to clarify I guess the 175 you referenced does that imply there is about 75 million of sort of wiggle room to reduce your CapEx budget for the year and also on that 175 is mostly [indiscernible] related and what’s the lead time for that the project in that 175 number? Joe Bob Perkins Okay 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 debt lease to 175. 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 and I just want to make sure that’s clear to everybody we are not going to be spending dollars in that category that aren’t well spent. And that investors don’t want us to spend and we have the 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 will require 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 battle, 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? Helen Ryoo Yes that does. But just to clarify so 250 is a sum of the four projects that were already identified that will cancel in 2016? Matthew Meloy No ma’am, no. Helen Ryoo Okay sorry so that’s the additional 275 is and 250 is outside of that number? Matthew Meloy Right 275 is the four projects, 250 is just coincidence that they are about the same magnitude. 250 is our estimate for a set of identified projects from a few months ago and 175 or more is the estimate of how much of that we will spend in 2016. Helen Ryoo Got it. Got it okay that is very helpful. And then the noble project it’s not coming online till 2017 but are going to get that cash flowing starting 2016 so are you… Matthew Meloy That’s not right either. Noble projects expected to come on the first quarter of 2018, but we will get cash flow in 2016 as a function of what has been a couple of renegotiation around the terms of that project or projects. We said from the beginning that we would not be economically disadvantaged by essentially one year auction as noble re-evaluated exactly what they wanted to do and payments in 2016 are a function of that. Helen Ryoo Okay that’s helpful. Just going back to your comments on counterparty risk just curious I guess you did have a little bit of Quicksilver exposure and it seems like that contract got rejected pretty early in their bankruptcy process just curious how was there anything special about that contract that made vulnerable or should we think a lot of these just transmission type of projects or contracts or typically more vulnerable in that situation if you could provide your view? Joe Bob Perkins you mentioned Quicksilver contract — currently other 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 would 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. And I would certainly not characterize any relationship I might have with that company or we are in renegotiation around that contract as being at all typical or having duplicates in line fractionation contract portfolio. Helen Ryoo Okay. And then just lastly Joe Bob on your comment about 130 million of negative effect with the commodity downturn after Atlas acquisition is that pre, does that take into account the hedge protection that came with Atlas or is that without that number? Joe Bob Perkins Well, 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 hedge. Helen Ryoo Okay, great. Thank you very much. Joe Bob Perkins Yes, thank you. Operator And our next question comes from Jeff Birnbaum from Wunderlich, your line is open Jeff Birnbaum Yes, good morning everyone. I got kicked off the call so I apologize if I duplicate any questions, but Matt did you mention if there were any deficiencies payments that you guys received in the quarter and if not were there? Matthew Meloy No we didn’t give a break out, we typically do receive some deficiency payments on our take or pay contract whether it be fractionation or on the GMP side, we didn’t 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 this time. Jeff Birnbaum Okay. Thank you and then just on the, back to LPG exports obviously you have, as you commented you seen some good strength the fourth quarter it seems like the first quarter to-date has been strong, I guess just given your comment about five million barrels a month being a good number to use this year relative to those kind of a more recent results. Can you talk a bit about how you see that driven either by seasonality or perhaps the first half relative to the back half and I mean you guys loved talked about this but have you added contracted balance since you last updated the market or not and then is that something you can quantify for us? Joe Bob Perkins I love to cross the table and Scott Pryor runs that business smiled at me. You don’t have anything long enough to hit me with so I am going to, but he can find me. Our five million barrels per month average for 2016 we believe is a good number for you and we gave that number actually some time ago. We said that 2016 was all to a good start there is 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’s relatively new business but there is a little bit of seasonal effect, the light first quarters going into second quarter as a function of global seasonal usage of water borne LPG and impacts something on the margin. You can see it in the last year’s performance we kind of half way expected and this year’s performance and I think that’s why either Matt or I mentioned some seasonality on average for 2016, we expect five million barrels per month I do not expect five million barrels every month. Is that help at all? Jeff Birnbaum Yes, Joe Bob thank you, it does help I guess just sort of as we think about sort of the current rate and then sort of once you get pass that seasonality I guess would you I guess the question is, do you expect a normal impact from seasonality or is there something greater this year that is taking it to the I guess what you call the five million barrels a month and accurate, a conservative number or a best guess number perhaps? Joe Bob Perkins Yes, I think you are parsing my statement. I think I said towards end of last year that I don’t better about that five million barrels a month estimate then we first put it out there and I feel at least that good. Does that help? Jeff Birnbaum It does. Okay thank you. Operator And our next question comes from Eric McCarthy from Citadel, your line is open. Eric McCarthy Hi good morning. Thanks. Joe Bob Perkins Good morning. Eric McCarthy You touched on ethane recovery in prepared remarks earlier, can you quantify or approximate ethane rejection across the system occurring? Joe Bob Perkins How much rejection is occurring? Eric McCarthy Yes. Joe Bob Perkins I don’t have that number for you I would characterize it as there is still significant amount of that thing rejection occurring among gathering and processing facility Targa and others who 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 cost they might have in NGLs, when they make those decisions we are on a long way from significant ethane extraction relative. Eric McCarthy I guess, your peers talk about how big the opportunity is over the next three years and if I think back to how much ethane out list was rejecting and then compare that to you system or just look if I take the approximately 250,000 barrels a day of NGLs being produced, I would say it’s 50% – 75% I think rejection because that’s along the order like 50,000 – 60,000 barrels a day they are being rejected? Joe Bob Perkins Yes, not providing a Targa number I have got a question for you when people are quantifying that what price do you think they are using for OpEx? Eric McCarthy I would imagine by 2018, 2019 if there is big demand there is going to be some uplift of those residual fuel value right. Joe Bob Perkins Well, I think you definitely got to the key, you have to inset the ethane to be extracted and if the ethane is being incentive to be extracted you got to increase in ethane prices ethane won’t go up by itself there will probably be a propane response propane and ethane will probably go together. The potential for that is a combination of volumes for fractionation and volumes and price for other NGLs and you said some upside potential for Targa, but there are a lot of variables to assume to come up what is that dollar potential. And it doesn’t make sense for Targa sort of pick one volume and one price and one outcome in 2018 to try to quantify for you right now. I don’t think. Eric McCarthy Okay. On the build out of that system do you have an approximate number of the current volumes that are being trucked out either on your acreage dedication or nearby? Joe Bob Perkins Its 1000 of barrels, okay. Eric McCarthy Okay so it’s and when you talk about building that system out further is that the opportunity is to capture those volumes currently being trucked or is it to expand to the wells that are scheduled to be completed over the course of the year? Joe Bob Perkins What Matt was characterizing relative to capital investment on the band lands. 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. And I think what I think you also heard and this is part of the equations is that we still expected gas to be up 2016 versus 2015 in the band lands and that all factors included, well declines we expected oil to be similar 2016 versus 2015 that are current view of activity levels. Eric McCarthy Okay alright that’s it from me thank you. Operator At this time I am showing no further questions I’d like to turn the call back over to Mr. Joe Bob Perkins for closing remarks. Joe Bob Perkins Thanks operator. To the extent anyone has any follow-up questions you are free to contact Jen, Matt or any of us. Thank you again for your time today and your interest and look forward to speaking with you again soon. Operator 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. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. 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Common Mistakes Most Investors Make

Individuals are consistently promised that investing in the financial markets is the only way to financial success. After all, it’s so easy. Financial pundits across the country state that one simply buys a basket of mutual funds and they will make 8, 10 or 12% a year. On a nominal basis, it is true that if one bought an index and held it for 20 years, they would have made money. Unfortunately, for most, it has not worked out that way. Why? Because no matter how resolute people think they are about buying and holding, they usually fall into the same emotional pattern of buying high and selling low . Investors are human beings. Human beings naturally want to be in the winning camp when markets are rising and seek to avoid pain when markets are falling. As Sy Harding says in his excellent book ” Riding The Bear ,” while people may promise themselves at the top of bull markets that this time they’ll behave differently : no such creature as a buy and hold investor ever emerged from the other side of the subsequent bear market .” Statistics compiled by Ned Davis Research back up Harding’s assertion. Every time the market declines more than 10% (and “real” bear markets don’t even officially begin until the decline is 20%) , mutual funds experience net outflows of investor money. Fear is a stronger emotion than greed . The research shows that it doesn’t matter if the bear market lasts less than 3 months ( like the 1990 bear ) or less than 3 days ( like the 1987 bear ). People will still sell out, usually at the very bottom, and almost always at a loss. The only way to avoid the “buy high/sell low” syndrome – is to avoid owning stocks during bear markets. If you try to ride a bear market out, odds are you’ll fail. And if you believe that we are in a new era where Central Bankers have eliminated bear market cycles, your next of kin will have my sympathies. Let’s look at some of the more common trading mistakes to which people are prone. Over the years, I’ve committed every sin on the list at least once and still do on occasion. Why? Because I am human too. 1) Refusing To Take A Loss – Until The Loss Takes You When you buy a stock, it should be with the expectation that it will go up – otherwise, why would you buy it? If it goes down instead, you’ve made a mistake in your analysis. Either you’re early, or just plain wrong. It amounts to the same thing. There is no shame in being wrong, only in STAYING wrong . This goes to the heart of the familiar adage: “let winners run, cut losers short.” Nothing will eat into your performance more than carrying a bunch of dogs and their attendant fleas , both in terms of actual losses and in dead, or underperforming, money. 2) The Unrealized Loss From whence came the idiotic notion that a loss “on paper” isn’t a “real” loss until you actually sell the stock? Or that a profit isn’t a profit until the stock is sold and the money is in the bank? Nonsense! Your portfolio is worth whatever you can sell it for, at the market, right at this moment. No more. No less . People are reluctant to sell a loser for a variety of reasons. For some, it’s an ego/pride thing, an inability to admit they’ve made a mistake . That is false pride, and it’s faulty thinking. Your refusal to acknowledge a loss doesn’t make it any less real. Hoping and waiting for a loser to come back and save your fragile pride is just plain stupid . Realize that your loser may NOT come back. And even if it does, a stock that is down 50% has to put up a 100% gain just to get back to even. Losses are a cost of doing business, a part of the game. If you never have losses, then you are not trading properly. Take your losses ruthlessly, put them out of mind and don’t look back, and turn your attention to your next trade . 3) More Risk It is often touted that the more risk you take, the more money you will make. While that is true, it also means the losses are more severe when the tide turns against you. In portfolio management, the preservation of capital is paramount to long-term success. If you run out of chips, the game is over. Most professionals will allocate no more than 2-5% of their total investment capital to any one position. Money management also pertains to your total investment posture. Even when your analysis is overwhelmingly bullish, it never hurts to have at least some cash on hand, even if it earns nothing in a ” ZIRP ” world. This gives you liquid cash to buy opportunities and keeps you from having to liquidate a position at an inopportune time to raise cash for the ” Murphy Emergency :” This is the emergency that always occurs when you have the least amount of cash available – Murphy’s Law #73) If investors are supposed to “sell high” and “buy low,” such would suggest that as markets become more overbought, overextended, and overvalued, cash levels should rise accordingly. Conversely, as markets decline and become oversold and undervalued, cash levels should decline as equity exposure is increased. Unfortunately, this is something never addressed by the mainstream media. 4) Bottom Feeding Knife Catchers Unless you are really adept at technical analysis, and understand market cycles, it’s almost always better to let the stock find its bottom on its own, and then start to nibble. Just because a stock is down a lot doesn’t mean it can’t go down further. In fact, a major multi-point drop is often just the beginning of a larger decline. It’s always satisfying to catch an exact low tick, but when it happens it’s usually by accident. Let stocks and markets bottom and top on their own and limit your efforts to recognizing the fact ” soon enough .” Nobody, and I mean nobody, can consistently nail the bottom tick or top tick . 5) Averaging Down Don’t do it. For one thing, you shouldn’t even have the opportunity, as that dog should have already been sold long ago. The only time you should average into any investment is when it is working. If you enter a position on a fundamental or technical thesis, and it begins to work as expected thereby confirming your thesis to be correct, it is generally safe to increase your stake in that position. 6) You Can’t Fight City Hall OR The Trend Yes, there are stocks that will go up in bear markets and stocks that will go down in bull markets, but it’s usually not worth the effort to hunt for them. The vast majority of stocks, some 80+%, will go with the market flow. And so should you. It doesn’t make sense to counter trade the prevailing market trend. Don’t try and short stocks in a strong uptrend and don’t own stocks that are in a strong downtrend . Remember, investors don’t speculate – ” The Trend Is Your Friend .” 7) A Good Company Is Not Necessarily A Good Stock There are some great companies that are mediocre stocks, and some mediocre companies that have been great stocks over a short time frame. Try not to confuse the two. While fundamental analysis will identify great companies, it doesn’t take into account market, and investor, sentiment. Analyzing price trends, a view of the ” herd mentality ,” can help in the determination of the “when” to buy a great company which is also a great stock. 8) Technically Trapped Amateur technicians regularly fall into periods where they tend to favor one or two indicators over all others. No harm in that, so long as the favored indicators are working, and keep on working. But always be aware of the fact that as market conditions change, so will the efficacy of indicators. Indicators that work well in one type of market may lead you badly astray in another. You have to be aware of what’s working now and what’s not, and be ready to shift when conditions change. There is no ” Holy Grail ” indicator that works all the time and in all markets. If you think you’ve found it, get ready to lose money. Instead, take your trading signals from the ” accumulation of evidence ” among ALL of your indicators, not just one. 9) The Tale Of The Tape I get a kick out of people who insist that they’re long-term investors, buy a stock, then anxiously ask whether they should bail the first time the stocks drops a point or two. More likely than not, the panic was induced by listening to financial television. Watching ” the tape ” can be dangerous. It leads to emotionalism and hasty decisions. Try not to make trading decisions when the market is in session. Do your analysis and make your plan when the market is closed. Turn off the television, get to a quite place, and then calmly and logically execute your plan. 10) Worried About Taxes Don’t let tax considerations dictate your decision on whether to sell a stock. Pay capital gains tax willingly, even joyfully. The only way to avoid paying taxes on a stock trade is to not make any money on the trade. If you are paying taxes – you are making money…it’s better than the alternative.” Steps to Redemption Don’t confuse genius with a bull market. It’s not hard to make money in a roaring bull market. Keeping your gains when the bear comes prowling is the hard part . The market whips all our butts now and then. The whipping usually comes just when we think we’ve got it all figured out. Managing risk is the key to survival in the market and ultimately in making money. Leave the pontificating to the talking heads on television. Focus on managing risk, market cycles and exposure. STEP 1: Admit there is a problem … The first step in solving any problem is to realize that you have a problem and be willing to take the steps necessary to remedy the situation. STEP 2: You are where you are … It doesn’t matter what your portfolio was in March of 2000, March of 2009 or last Friday. Your portfolio value is exactly what it is rather it is realized or unrealized. The loss is already lost and understanding that will help you come to grips with needing to make a change. STEP 3: You are not a loser … You made an investment mistake. You lost money. It has happened to every person that has ever invested in the stock market and anyone who says otherwise is a liar! STEP 4: Accept responsibility … In order to begin the repair process, you must accept responsibility for your situation. Continue to postpone the inevitable only leads to suffering further consequences of inaction. STEP 5: Understand that markets change … Markets change due to a huge variety of factors from interest rates to currency risks, political events to geo-economic challenges. Does it really make sense to buy and hold a static allocation in a dynamic environment? The law of change states : that change will occur and the elements in the environment will adapt or become extinct and that extinction in and of itself is a consequence of change . Therefore, even if you are a long-term investor, you have to modify and adapt to an ever-changing environment otherwise, you will become extinct. STEP 6: Ask for help … Don’t be afraid to ask or get help – yes, you may pay a little for the service but you will save a lot more in the future from not making costly investment mistakes. STEP 7: Make change gradually … Making changes to a portfolio should be done methodically and patiently. Portfolio management is more about ” tweaking ” performance rather than doing a complete ” overhaul .” STEP 8: Develop a strategy … A goal-based investment strategy looks at goals like retirement, college funding, new house, etc. and matches investments and investment vehicles in an orderly and designed portfolio to achieve those goals in quantifiable and identifiable destinations. The duration of your portfolio should match the “time” frame to your goals. Building an allocation on 80-year average returns for a 15-year goal could leave you in a very poor position. STEP 9: Learn it…Live it…Love it … Every move within your investment strategy must have a reason and purpose, otherwise, why do it? Adjustments to the plan, and the investments made, should match performance, time and value horizons. Most importantly, you must be committed to your strategy so that you will not deviate from it in times of emotional duress. STEP 10: Live your life … The whole point of investing in the first place is to ensure a quality of life at some specific point in the future. Therefore, while you work hard to earn your money today, it is important that your portfolio works just as hard to earn your money for tomorrow.

ONEOK’s (OKE) CEO Terry Spencer on Q4 2015 Results – Earnings Call Transcript

Operator Good day, and welcome to the fourth quarter 2015 ONEOK and ONEOK Partners earnings conference call. Today’s call is being recorded. At this time, I would like to turn the conference over to Mr. T. D. Eureste. Please go ahead, sir. T. D. Eureste Thank you, and welcome to ONEOK and ONEOK Partners fourth quarter and yearend 2015 earnings conference call. A reminder, that statements made during this call that might include ONEOK or ONEOK Partners expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provisions of the Security Acts of 1933 and 1934. 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. Our first speaker is Terry Spencer, President and CEO of ONEOK and ONEOK Partners. Terry? Terry Spencer Thank you, T. D. Good morning, and thanks for joining us today. As always, we appreciate your continued interest in investment in ONEOK and ONEOK Partners. On this conference call is Walt Hulse, Executive Vice President of Strategic Planning and Corporate Affairs; Derek Reiners, our Chief Financial Officer; Wes Christensen, Senior Vice President, Operations; Sheridan Swords, Senior Vice President, Natural Gas Liquids; Kevin Burdick, Senior Vice President, Natural Gas Gathering and Processing; and Phil May, Senior Vice President, Natural Gas Pipelines. Additional key financial and operational information has been updated in a short presentation and is posted on ONEOK’s and ONEOK Partners’ websites. Let’s start by discussing ONEOK and ONEOK Partners accomplishments in 2015. Then I’ll hand it off to Derek for financial update, and finish by reviewing our 2016 financial guidance, which we maintained for both ONEOK and ONEOK Partners in last night’s release. Our uniquely-positioned assets delivered higher ONEOK Partners fourth quarter and 2015 adjusted EBITDA in a very challenging market, and we delivered on our expectation to significantly grow natural gas and natural gas liquids volumes and earnings in the second half of the year. The partnership grew its adjusted EBITDA throughout the year by nearly 40% from the first quarter to the fourth quarter 2015, ending the year with $450 million in fourth quarter adjusted EBITDA. The partnership also improved its quarterly distribution coverage to 1.03x. These results were driven by a significant ramp in natural gas volumes gathered and processed across our system, especially in Williston Basin, as we connect in more than 820 additional wells; captured more flared volumes from existing wells; completed six field compression projects and our Lonesome Creek natural gas processing plant; and restructured several contracts earlier than expected; and in the Mid-Continent, volumes increased late in the year, as a large producer customer completed wells that had been drilled earlier in the year. The Natural Gas Liquids segment, which is connected to more than 180 natural gas processing plants, continued to benefit from natural gas liquids processed volume growth in Williston Basin. Seven new third-party natural gas processing plants were connected in 2015. We also realized solid volume performance on our West Texas LPG pipeline system from our long haul customers, as we continue to provide quality service at a good value. With nearly 100% of its earnings fee-based, the Natural Gas Pipeline segment had another solid year. This segment is taking advantage of incremental demands due to lower natural gas prices through its uniquely positioned assets with the announcements of the Roadrunner Gas Transmission Pipeline and WesTex Pipeline expansion, serving growing markets in Mexico. In 2015, we made significant progress toward reducing commodity risk in our business, which is expected to reduce earnings volatility over the long-term. As a result, we expect 2016 fee-based earnings to be approximately 85%, a significant improvement from 66% in 2014. Drivers of this increase include, growing the fee-based exchange services volumes in the Natural Gas Liquids segment and contract restructuring in the Gathering and Processing segment. The efforts of contract restructuring in the Gathering and Processing segment can be seen by the increase in our average fee rate. The average fee rate for the fourth quarter 2015 was $0.55, a nearly 60% increase compared with $0.35 in the first quarter 2015. At ONEOK, we remain committed to being a supportive general partner, as evidenced by the $650 million equity investment in the partnership in mid-2015, which we expect to result in increased distributions from ONEOK’s higher ownership percentage in ONEOK Partners. Our extensive integrated network of natural gas and natural gas liquids assets delivered solid results in 2015 and has positioned us well for 2016. That concludes my opening remarks. Derek? Derek Reiners Thanks, Terry. I’ll start by highlighting the financial steps we took in 2015 and early-2016 that positioned us well for 2016 and into 2017. With a high priority on maintaining the partnership’s investment grade credit ratings, we took decisive steps to manage its balance sheet by high grading its growth projects and reducing capital spending by nearly $1.6 billion in 2015 from our original 2015 capital guidance. We issued $750 million of equity in August, along with nearly $280 million of additional equity through the at-the-market program during 2015. Termed out $800 million of short-term debt in March and most recently entered into a $1 billion three-year unsecured term loan, which effectively refinances the 2016 long-term debt maturities at a low cost. With the financial steps we’ve taken and the momentum and volume growth and earnings leading into 2016, we expect to achieve our 2016 financial guidance. At ONEOK Partners we expect not to need public debt or equity issuances well into 2017, which includes no equity from the aftermarket equity program, to keep distributions flat for the year, deliver distribution coverage of 1x or better for 2016 and obtain GAAP debt to EBITDA ratio of 4.2x or less by late 2016. At ONEOK, we expect to keep this dividends flat for the year, pay no cash income taxes in 2016 and generate approximately $160 million of free cash flow after dividends in 2016, which along with $90 million of cash at the end of 2015 provides ONEOK with significant flexibility to support ONEOK Partners, if needed. For growth capital in 2016, we expect to spend $320 million in the Gathering and Processing segment and $70 million each in the Natural Gas Liquids and Natural Gas Pipelines segments for a total of $460 million as previously guided. As producer needs evolve throughout the balance of the year and into 2017, we have the flexibility to significantly reduce growth capital, particularly in the Gathering and Processing segment, as we optimize our systems and available capacity. Additionally, we have been able to realize reduced operating costs and capital costs from our service providers across our operations. We continue to control operating costs and have reduced contract labor. We expect this trend to continue into 2016. As it relates to maintenance, capital expenditures we take a conservative approach. We’re extremely careful not to underestimate expenditures, when establishing guidance spending, for the integrity and reliability of our assets is very important to the partnership’s success. Over the long-term, our assets have operated very reliably as a result of this approach. In 2015, a number of our large maintenance projects came in significantly under budget, especially the projects scheduled towards the second half of 2015, as service providers reduced costs and did very aggressively due to market conditions. On the topic of counterparty credit risk, we consider our credit exposure to be low across all three of our operating segments. The partnership had no single customer representing more than 10% of revenues and only 15 customers individually represented 1% or more of revenues. Additionally, of the top 10 customers, which represented 38% of revenue, nine are investment grade or provide full credit support. Many of our top 10 customers are Natural Gas Liquids segment customers comprised of large petrochemical and integrated oil companies. Taking a look at our credit profile within our three segments, where we consider investment grade is rated by the ratings agencies or comparable internal ratings or secured by letters of credit or other collateral. The Natural Gas Pipeline segment received more than 85% of its 2015 revenue from investment grade customers, who were primarily large electric and natural gas utilities. The Natural Gas Liquids segment has limited credit exposure in its exchange service fee earnings, as in those contracts the natural gas liquids are purchased and proceeds are remitted from the partnership to the liquids producer less fee. And more than 80% of 2015 commodity sales were to investment grade customers. And finally, the Gathering and Processing segment’s credit risk is limited, as in most contracts the partnership remits the proceeds under the percent of proceeds contracts to the producer, net of ONEOK Partner share of those proceeds as well as the fees charged. 99% of the segment’s 2015 downstream sales were to investment grade customers. 2015 results at both ONEOK and ONEOK Partners include the impact from non-cash impairment charges totaling $264 million, primarily related to investments in the coal-bed methane area of the Powder River Basin. The partnership remains highly committed to maintaining our investment grade credit ratings, having a solid balance sheet and ample liquidity to support our capital program, ending 2015 with $1.8 billion available on its credit facility. The partnership’s GAAP debt to adjusted EBITDA on a run rate basis is 4.1x, reflecting earnings growth during the year. Distribution coverage remains an important metric for us as well. We expect distribution coverage of 1x or better for 2016, by growing our cash flows through volume growth, cost savings and efficiency improvements. ONEOK on a standalone basis ended 2015 with over $90 million of cash and an undrawn $300 million credit facility. The partnership is advantaged by having a strong supportive general partner in ONEOK. With a significant excess dividend coverage, ONEOK has the resources, that may be used to further support the partnership, if needed, as it navigates these uncertain times. Terry, that concludes my remarks. Terry Spencer Thank you, Derek. Let’s walk through our 2016 financial guidance and key assumptions by segment. Starting with our largest segment, the Natural Gas Liquids segment is expected to contribute $995 million in operating income and equity earnings in 2016. Additionally, we expect the natural gas liquids volumes and earnings to be weighted towards the mid to second half of 2016. Approximately 90% of the expected earnings in this segment are fee-based from the exchange services and transportation businesses. We continue to expect the partnership’s natural gas liquids volumes gathered to increase in 2016, primarily from Williston Basin natural gas liquids volume growth expected from our gathering and processing assets in the Basin, including the expected connection of the Bear Creek plant and one third-party natural gas processing plant in 2016. Approximately 60% of the segment’s natural gas liquids volumes gathered come from the Mid-Continent, with the majority of the gathered volume coming from third-party processing plants. Our unique natural gas liquids position in the Mid-Continent is similar to the position we have in the Williston, with the partnership’s gathering and processing assets as we are connected to most of the third-party plants in the region. We expect to continue to benefit from natural gas liquids volumes gathered through our West Texas LPG system, where nearly 26% of the segment’s volume originates. The segment is connected to more than 60 natural gas processing plants in the Permian Basin and is expected to connect one additional plant in 2016, and we expect to receive the full benefit in 2016 of increased tariffs. Finally, we moved the completion of the Bakken NGL pipeline expansion to the third quarter 2018, due to a slower expected rate of volume growth. The realigned timing of the expansion has no impact on financial or capital guidance for 2016. Driving the earnings growth in the Natural Gas Gathering and Processing segment in 2016 is natural gas volume growth in the Williston Basin and enhanced margins due to the contract restructuring efforts. In the Williston, we expect to average 740 million cubic feet per day of natural gas gathered volume in 2016. Our gathered volumes early in the year have been very strong, as we reach nearly 800 million cubic feet per day in February. The recently completed Lonesome Creek plant and compression projects have already added nearly 100 million a day of incremental volume to our system, most of which has come from capturing previously flared gas. We continued to have approximately 24 rigs operating and more than 500 drilled uncompleted wells on our dedicated acreage. Given this activity, we expect 250 to 350 new well connections to our system in 2016. To put the expected 2016 volume outlook into context, if every rig were to have stopped drilling on January 1, 2016, and we did not connect any new wells in 2016, we would expect an average gathered volume of 720 million cubic feet per day in 2016, slightly below our guidance for the Williston. Natural gas volume growth in 2016 will not reflect a pronounced second half ramp up, as we experienced in 2015. We do expect volumes to slightly decline through the summer, until our 80 million cubic feet per day Bear Creek plant comes online and we expect to capture an incremental 40 million cubic feet per day of gas currently flaring in Dunn County. In the Mid-Continent, we continued to be in constant communication with our producer customers regarding their drilling and completion activity. And similar to the Williston, the Mid-Continent volume exited 2015 at a high rate. As I mentioned earlier, the segment did receive an early benefit from our contract restructuring efforts in the fourth quarter 2015. However, 2016 is expected to receive the full benefit of these efforts and we expect another increase in the average fee rate in the first quarter 2016 from the $0.55 the segment averaged in the fourth quarter 2015. In the Natural Gas Pipelines segment, 2016 earnings are expected to remain more than 95% fee-based, with more than 90% of the segment’s transportation capacity and more than 75% of its natural gas storage capacity contracted for the year. The first phase of the Roadrunner Gas Transmission Pipeline is on schedule to be complete next month, and is fully subscribed under 25-year firm demand charged fee-based commitments, with the second phase expected to be complete in the first quarter 2017. Before closing, I would like to discuss future demand growth for ethane, which we expect to be a significant opportunity for the Natural Gas Liquids segment, as we move through 2017 and 2018. Approximately 400,000 barrels per day of incremental ethane demand from new world-scale petrochemical crackers is expected to come online by the third quarter of 2017 and nearly 164,000 barrels per day more by first quarter 2019. We expect this new demand combined with additional ethane exporting infrastructure to significantly reduce the ethane excess supply overhang and put pressure on ethane prices, and bringing most natural gas processing plants into full ethane recovery some time in mid-2018. Nearly one-third of U.S. ethane or approximately 180,000 barrels per day is dedicated and connected to our natural gas liquids systems, but it’s currently not producing due to insufficient ethane demand. We are well-positioned to transport and fractionate substantial incremental ethane volumes, once the natural gas processing plants we are connected to transition into full ethane recovery in response to growing U.S. petrochemical demand. We expect little to no additional capital expenditures needed to bring this ethane onto our system, as we already constructed the natural gas liquids infrastructure necessary to connect supply to the Gulf Coast region. The total incremental adjusted EBITDA benefit to the partnership, if all of the natural gas processing plants we are connected to enter full ethane recovery, could be in the range of $200 million per year. With the Natural Gas Liquids segment’s unique and extensive asset position, we can deliver significant ethane supplies to the Gulf Coast markets from the Williston, Mid-Continent and Permian Basins. Since we issued guidance in December, the commodity price environment has continued to be unstable, and many of our producer customers have reduced their capital expenditure plans for 2016. While these challenges remain, we will continue to remain focused on serving our customers, reducing risks, controlling costs, managing our balance sheet prudently and reducing capital needs. As we have discussed on this call, more than 85% of the partnership’s operating income and equity earnings comes from primarily fee-based activities, underpinned by its large 37,000 mile integrated natural gas and natural gas liquids network, with opportunities to grow its cash flows, even in a lower capital spending environment. In 2016, we expect to finish the year within our financial guidance, driven by our uniquely positioned assets. We are less than 60 days into 2016 and we expect similar to 2015 opportunities and challenges throughout the year. We will be proactive in our approach to these opportunities and challenges and prudent in our decision making, all while keeping in mind the long-term interest of our investors. I’d like to thank our employees across the country for their strong performance, hard work and dedication in 2015. Many of our employees have experienced these difficult industry cycles before, and they know what to do. Manage costs, be efficient, be creative and operate safely and reliably, all while being focused on providing quality service to our customers. And many thanks to all of our stakeholders for your continued support of ONEOK and ONEOK Partners. Operator, we’re now ready for questions. Question-and-Answer Session Operator Operator Instructions] And our first question will come from Eric Genco with Citi. Eric Genco My first question is actually a little bit of a two-parter. I just want to dig a little more on the potential on the ethane recovery. It obviously seems like this is a pretty major opportunity and no incremental capital. Not really if, but maybe when. And I know it’s early, I just would like to get a better sense for the timing and maybe the mechanics, and how that some of this might play out in terms of the split between where you’ll feel the impact in the Permian, Mid-Continent and the Bakken? And I guess also in light of the comment that you alluded to in your remarks that perhaps the Permian is going to see a meaningful uplift even in ’16 in terms of the rate, bringing that more to market rates. I’d just like to get a better sense for that, if you can? Terry Spencer Sure. Eric, I’ll just make a couple of comments, and then let Sheridan kind of follow this thing. You see, in the slide deck that we provided, there is actually a slide in there that kind of shows you the sources of where that incremental ethane originates. And if you think about it in terms of which ethane is going to come on, obviously those with the lowest transportation cost burden will come on sooner. So you have to think about in terms of the Gulf Coast probably coming on sooner, the Mid-Continent and the West Texas probably next, and then you got to think about the Marcellus and the Rockies. It’s kind of in that order and we provided that table to give you as industry what that volume impact is? So Sheridan, you want to provide little more color and then talk about West Texas? Sheridan Swords Only thing I would say is that, I think we’ll start seeing — as we enter into 2017, is when we will start seeing meaningful ethane starting to come out. And as Terry said, West Texas of our system will be first, but that is where we have the least amount of ethane rejection on our system followed by the Mid-Continent, where we have the most volume off currently, and then last will be ’18 or beyond, which will be the Bakken. In terms of West Texas pipeline and the rate increase, in July of 2015, we brought the tariff rates, the uncommitted tariff rates, on the West Texas pipeline closer to market, so we only realized half the year of that rate increase, which in 2016 will realize the complete year of that rate increase. Eric Genco But that’s not necessarily getting you to the sort of 5x to 7x as sort of the long-term target, it’s more just the benefit of half the year at this point? Sheridan Swords Yes, [multiple speakers] full year. We don’t anticipate raise in rates. We don’t have in our guidance raising rates further on West Texas in 2016. Eric Genco And I guess, in switching gears a little bit maybe, I’d just like to get some of your thoughts on your most recent conversation with the rating agencies and how that’s going. I mean, you have alluded to all the accomplishments and the things that were on their checklist in 2015, the equity offering in August, renegotiating POP, addressing refinancing for ’16, but in light of it, I guess, some of the more recent actions sort of in the E&P space, I’m curious, if there’s been any shift in the tone or the targets they’ve set for you? And I’m also curious to what extent they have looked at the potential uplift for ethane. And I know it’s typical in some leverage ratios to make an adjustment for capital that’s already in the ground and earnings slightly to come on. Is that something that they are considering and looking at, at this point, or is it too early to tell? Derek Reiners We do communicate regularly with the credit rating agencies, and certainly we intend to continue to do so. I think we’ve got a long track record of taking those prudent actions and you checked them off the list pretty nicely, just as I would. The term loan and sort of being ahead of our financing needs, I think, is helpful and those things driving commodity risk out, reducing capital, I think all of those sort of credit-friendly actions that we have taken over time plays into their thought process. I can’t tell you to what extent they may or may not be including ethane uplift. I suspect not much. But historically, they’ve understood and added back some credit, I think, for the capital spending over time. So what I think they look for is a track record, a plan to continue to reduce leverage. And as I mentioned in my remarks, the GAAP debt to EBITDA of 4.1x on a run rate basis is certainly supporting that we’re headed in the right direction. And I think the unique aspects of our footprint, the tailwinds in terms of volume that Terry mentioned in the Williston, capturing the flare gas, those sorts of things I think all play into their thought process. Terry Spencer Derek, the only thing I would add to that is that I think the rating agencies from a macro perspective are aware of the growth that’s happening in that petrochemical space. Now, whether they actually take that into consideration in any of their analysis, as Derek indicated, we don’t know. But I think, they’re certainly aware of it. And I think if you were to ask them about it, I think that they do view it as a strong positive, but whether they’ve actually factored that into any analysis, again, we don’t know. Operator Moving on, we’ll go to Christine Cho with Barclays. Christine Cho In the presentation, you guys show that the Natural Gas G&P volumes are 662 million cubic feet a day in the Rockies for the quarter. Would you be able to split that between Powder River and Williston? Terry Spencer Christine, I’ll let Kevin handle that. Kevin Burdick Yes. Christine, you can assume there is roughly 30 million a day of Powder Gas in that number. Christine Cho And then I just wanted to touch on the ethane opportunity that you guys talked about. As you guys say, and on the slide you guys point to that 150,000 to 180,000 barrels per day being rejected across your system. Could you split that up a little better from Williston, Mid-Continent, and Permian? I know you said the least amount is coming out of the Permian, but any sort of percentages or ballparks would be helpful. Sheridan Swords You have over 100,000 barrels a day of ethane off in the Mid-Continent, more like 120,000 to 125,000; 36,000 in the Bakken; and virtually 10,000 or less in the Permian. Christine Cho And then as a follow-up to that question, you guys have a whole bunch of NGL distribution pipes leading to the Gulf Coast from Conway and Mid-Continent. What’s the utilization currently on all the pipes between those two points and are you guys collecting minimum volume payments for any of the volumes? Asked another way, are customers currently paying for volumes they aren’t shipping? Sheridan Swords See the capacity we have between Conway and Mont Belvieu is about 60% utilized between the Sterling pipelines and the Arbuckle pipelines. And when we think about our minimum volume commitment that’s usually for a bundled service, so yes, there are some minimum volumes that have Belvieu redelivery that we are collecting today. Christine Cho I’ll follow up offline, but lastly, is there sufficient ethane fractionation capacity in storage along the Gulf Coast to accommodate all this ethane that’s going to have to come out? Sheridan Swords On our system, we have enough ethane through our fraction — we have enough capacity through our fractionators to fractionate all of the ethane on our system. And we do have the storage capacity and the connectivity into the petchems to be able to deliver that to market. Christine Cho But that’s specifically for your system. I was kind of more asking like does the industry have enough? Sheridan Swords Christine, you’d have to ask all the other individuals, fractionators down there. But my sense is yes, there is plenty of capacity to frac this ethane. Most of the fractionators when they are constructed, they are constructed for a full ethane slate. And so when this ethane is being rejected, it just takes it out [multiple speakers] first tower of the fractionators. Christine Cho Perfect, that’s what I thought. Operator And moving on, we’ll go to Becca Followill with U.S. Capital Advisors. Becca Followill I think you guys talked about that your guidance included about 300 to 350 well connects in the Williston Basin during 2016, for I’m correct? Terry Spencer It’s 250 to 350. Becca Followill What I’m looking at on Page 8 of the presentation on your guidance of 740 million a day, it looks like that includes a 100 well connects? Terry Spencer I’m going to make just a general comment about that slide, Becca, and then I’ll let Kevin jump into more of the detail. But that’s a theoretical depiction assuming that all of the flare gas gets connected and that we experience a 20% decline, and based upon that, you would need 100 wells. But now, I’ll let Kevin take it the rest of the way. Kevin Burdick Yes. So Becca, there are a couple of things and dynamics that are going on in that, transitioning from that slide to our guidance. Like Terry mentioned, that’s kind of a theoretical, assuming all the flares were out. Well, in our guidance volumes, we factor in some level, a minimal level of flaring. And keep in mind; we’ve got Dunn County where gas is going to flare until we get the Bear Creek plant built in the third quarter. We also factor in a little bit for weather during the winter months. And then just some general operational cushion or whatever you want to call it just to pull volumes back a little bit. So that’s the incremental difference between the 100 well connects that’s referenced in the stair-step slide and our guidance. But we do feel strong when you look at the activity that’s currently there in the basin, and the number of rigs on our acreage and then you look at the drilled and uncompleted backlog, we feel that the 250 to 350 is a really good number to achieve. Becca Followill And that’s even despite recent announcements by some of the producers about suspending completion and pairing back budgets, correct? Kevin Burdick Yes. Operator And next we’ll go to Craig Shere with Tuohy Brothers. Craig Shere So expanding on Eric and Christine’s ethane recovery question, how should we be thinking about margins regionally as ethane recovery rolls in? It’s not going to be — you’re not going to get over $0.30 out of the Bakken, are you? Sheridan Swords We will not receive $0.30. Typically across our whole system ethane has discounted to the C3 plus, so we will realize a lower margin than the $0.30 out of the Bakken. Craig Shere I mean, roughly speaking, against what you’re getting on the C3 plus, should we be thinking like nickel-plus spreads or what should we be thinking? Is it even those spreads across the system? Sheridan Swords No, it will not be even across the system. Some volume will come on that will have Conway options, some volume will have Bellevue options. And they have all different kind of spreads depending on where they are. Obviously, if you’re in the Bakken, they are going to have the highest margins and the Mid-Continent will be lower, and obviously a little bit in the Permian will be the lowest. Terry Spencer And Craig, just let me step in here. So you used the word spreads, I think they are fees. It’s not a spread play; it’s a fee. And so there will be different rates, as Sheridan indicates, for different areas. And it’s very common for us to have a lower fee rate for the ethane component than the C3 plus barrel. Craig Shere I kind of meant the discount to what you’re charging for the C3 plus, that’s the spread I was referring to. Terry Spencer I understand now. I was just trying to make sure, I don’t have any misunderstanding. Craig Shere And thinking about 2017 capital needs, I understand you don’t have any need to raise debt or equity until well into ’17, but your growth CapEx in ’17 for the already approved projects and execution should fall off really materially year-over-year. So when you think about incremental capital needs in ’17, is that just terming things out, rightsizing the balance sheet a little bit, I mean there’s not a lot of spend that you have planned, right? Terry Spencer I think that’s a fair assessment Craig. We don’t have anything of major strategic significance, in particular, in the G&P segment for 2017. So yes, you are thinking about it the right way. And in particular, if we get in this lower-for-longer mode, we do have the ability to flex down our current rate of capital spend down considerably. Now, we’ve not guided to that, don’t intend to guide to that in this call, but I think you’re thinking about it the right way. Craig Shere Is there some range or percentage that you think you can shave-off in a worst-case scenario? Terry Spencer Well, let me give you this, it’s significant, and you could get to a point where just your routine growth, well connects, small infrastructure projects, compressor type projects could be the — the core of your organic growth opportunities is that kind of stuff. And so it would be a significant reduction in the capital spend that we’re experiencing here in ’16; significant reduction in ’17, if the lower-for-longer environment persists. Craig Shere And last question, following-up on Becca’s query about the 100 well connects on that theoretical slide versus the 250 guidance. I know we’re in a period of flux and who knows what’s going to happen next quarter, but implicit in that questioning is that you continue to have a cushion supporting your operations in a worst-case scenario, even in ’17, because you’re not using it all this year in terms of flared gas and the drilled, but uncompleted well inventories. Do you want to address any of that in terms of how measurably things may or may not fall off next year in a worst-case scenario? Terry Spencer Well, let me make a comment and then Kevin can kind of clean it up. So flared gas, let me just tell you, it’s not an exact science. And it’s quite possible we could have more flared gas than we actually believe we have, because every time we turn on a compressor station it seems like the wells behind that particular compressor station outperform our expectations. Time and time again, more gas is showing up than what we thought. And so that’s what we’re dealing with here, that’s what we dealt within the fourth quarter of last year and that’s what we’re dealing with, as we plow through first quarter 2016. So yes, I think we would expect that it’s probably not going to turn out exactly the way we think. And it could very possible that we’re a big conservative on our assessments and thoughts about flared gas. Kevin, do you have anything to add to that? Kevin Burdick The only thing I would add, Terry, is that, again, back to the drilled, but uncompleted backlog, when you think about that we’ve got 550 or a little more than that behind our acreage. I don’t think there’s any expectation that all of that’s going to get worked up this year. So as you move into through this year and you move into ’17, even if the flared gas volumes go very low, you’ve still got some support from that drilled, but uncompleted backlog, that producers can bring on relatively quickly as prices improve. Operator And next we’ll go to Jeremy Tonet with JPMorgan. Jeremy Tonet Just wanted to touch back on the call, as far as the $0.55 fee that you guys saw, how do you expect that to trend during 2016 again? Terry Spencer So Jeremy, we’re not going to guide in the first quarters to what that fee rate is going to be, but we are expecting it to increase. And if there’s any other color, I’ll let Kevin address it. Kevin Burdick Yes. Jeremy, I mean we did experience an increase in the fourth quarter that was a little ahead of our expectations by getting some of the restructurings done earlier than anticipated. So while we do expect it to increase, I don’t think it would be as pronounced as the increase from Q3 to Q4. Jeremy Tonet One of the questions we commonly get in this space is thinking about maintenance CapEx. How do you guys think about it as far as the depletion to the wells, how do you think about well connects as far as maintenance CapEx? And did that impact the maintenance CapEx revisions over the course of the year or any color you could provide there would be great. Terry Spencer Yes, Jeremy, how we look at it — and Derek can jump in here if I mess this up. But when we think about growth capital, well connects, and those types of things, the volume through our systems, we consider that growth capital. If it’s attached to revenues, if it’s a revenue generating activity, we call it growth. If it’s related to the straight-up maintenance of the pipelines systems and mechanical integrity of the assets we call that maintenance capital. And that’s the distinction, we’ve used for a long time and I think many of our peers use that same thought process. Does that help you? Jeremy Tonet Maybe just in general, as far as maintenance CapEx coming in lower across the year, if you could just help us think through that a bit more as far as like savings through reductions in contractors or any color there would be great? Terry Spencer I’m going to let Wes Christensen to take that. Wesley Christensen Sure. In 2015, we did benefit from lower contractor costs across our projects, as well as using less contractors. Also our materials and supplied that we consume inside of those projects, we’ve seen some benefit in lower cost there as well. And then the last item maybe just the timing of the projects, we expect to see these types of trends continue through 2016. Jeremy Tonet And then just one last housekeeping item. I think there was an asset sale gain of about $6 million in the quarter. Could you provide some color on that please? Derek Reiners We routinely will sell-off small pieces of pipe for things like that, that really aren’t integral to our systems. So that’s all that is. I think it’s fairly consistent from year-to-year actually we’ve got kind of a kind of a small amount every year, it really only impacts DCF by less than $1 million. Jeremy Tonet So the $6 million, was that non-cash item that’s backed out in DCF then? Derek Reiners Exactly. Operator And next will go to Kristina Kazarian with Deutsche Bank. Kristina Kazarian Just wanted to make sure I was understanding something that was asked earlier about leverage and rating agencies. Can you just help me understand how the conversations have been going, because I think OKS is still on negative at both? I mean you guys have listed a bunch of positives you guys have executed on since then, so what should I be watching for or thinking about or have they communicated what you guys need to execute in order to have OKS removed from negative outlook at either? Derek Reiners Of course, they wanted to see us execute on those things I mentioned before. Broadly the macro environment, I think is difficult for them to take us off of any sort of a watch at this point. We really forced our hand last year in August, when we did the ONEOK bond deal where they had to rate that debt, that’s when they put us on negative outlook. So my personal opinion is it’s difficult for them to remove that given the broader macro environment, the low pricing and so forth. Terry Spencer Just Christine, and the only thing I would add to that as I think they’ve been appreciative of the fact that we’ve decisively cut capital spending, have made some really prudent decisions and that we’ve voiced to them our willingness to continue to cut capital, if the environment dictates. Kristina Kazarian That’s great, which leads into my second follow-up one. And I know you mentioned this earlier about the flex down on possible spend, and I’m not looking for a number at all there, but if I think about it being a lower-for-longer environment, can you touch on maybe some other things you might think about, too? So are there small like non-core asset sales? How do I think about maybe — I know there was a number in the press release, but financial support OKE could provide for OKS and just things in that vein? Terry Spencer Well, Kristina, we obviously evaluate our assets at all times, but we don’t see asset sales as a primary driver for us going forward. The financial flexibility that we have from ONEOK generating excess cash gives us plenty of different tools that we can use, whether it be equity purchases or considering thoughts around the IDR. We constantly evaluate what would be best for ONEOK and ONEOK Partners and we’re happy to have those tools at our disposal as we move forward. Kristina Kazarian And then last one from me, so I know we saw the fee increase in the 4Q was ahead of expectations. Just an update on progress and in terms of like how many contracts left, could I see renegotiations on or anything color there? Terry Spencer Kristina, most of our objectives have been met in the Williston Basin, but generally speaking, we continue to, where we can, renegotiate contracts to reduce commodity price exposure and where we can increase margin. So that’s just an ongoing process. There might be a few more in the Williston, but as I said, for the most part we’re done there. Western Oklahoma and Kansas, of course, will be areas of our continual focus. Operator And next will go to Elvira Scotto with RBC Capital Markets. Elvira Scotto Thanks for all the color that you provided on sort of your volume expectations in the Williston Basin. But do you think maybe you can provide a little more color behind your Mid-Continent volume guidance, especially given how the commodity price environment has changed and producer commentary? And can you provide any, I don’t know, maybe some sensitivity around that guidance? Terry Spencer First of all, Elvira, my contribution is going to be that rig counts in the Mid-Continent have been pretty resilient even in this latest leg down compared to some of the other basins. So I think that’s been somewhat surprising to us. So Kevin, if you want to talk a little bit more specifically on volumes? Kevin Burdick Yes, the Mid-Continent area, especially the Stack, Cana, SCOOP areas, it’s kind of interesting; because you’ve got really competing data points. Even as late as last week with some calls that we’re out there, the performance and the results that many of our customers and other producers in the area are seeing are really outstanding, but yet there is some discussions of some delays. And we are watching that very closely, we’re in constant communication with all of our customers in the Mid-Continent. I guess the way I think about it; it’s really a function of just time. Those reserves are there, the results are strong, so the volumes will come, it’s just, okay, is it going to be fourth quarter of this year, third quarter of this year or a push into ’17, we’ll be watching that closely over the next couple of months. Elvira Scotto And then in terms of cost cutting opportunities, do you see any cost cutting opportunity in 2016 and is that baked into your guidance? Terry Spencer Elvira, yes, we do have some continued management of our cost. And obviously, we’re still seeing a downward pressure on vendor cost and we’ve got contractor costs that are coming down, particularly as we’re in a lower growth mode. Wes, do you have anything else you could add to that? Wesley Christensen No, I think that’s consistent. We’ll see that in our O&M, as well as we been seeing it in our maintenance capital. Operator And our final question will come from John Edwards with Credit Suisse. John Edwards Terry, I’m just curious on the guidance, you affirmed the guidance, but obviously since you’ve provided it things have deteriorated significantly. So what improvements, I guess, are you looking to in your own performance there that would enable you to affirm if you could? Terry Spencer Well, certainly, John, the outperformance and the exceedance of expectation in volume performance is really key. We continue to be very well hedged, as you can see from the information that we provided to you. And we’re going to get the full year of the contract restructuring benefit in 2016. So from a pricing point of view standpoint, we think that there’s going to be some correction or some significant improvement in prices, as we move throughout the year based upon our current point of view. So as we sit today, we like our guidance. And as Kevin indicated, we’re going to continue to assess producer activity and try and get as much visibility as we can. And if we think updates are necessary, we’ll come back to you. John Edwards And then just you may have covered this, I got disconnected part of the call. But in terms of the, you were pointing on the NGL segment sort of a second half volume story there. If you could just provide a little bit more color or detail on how you see that playing out? Sheridan Swords Well, first, we start up in the Bakken as you saw the volumes, even though they’re slower growth than we saw last year, they continue to grow, especially with the Bear Creek plant coming online. And also, we’re going to connect a third-party processing plant up there as well this year. And we have plants in the Mid-Continent that are in the SCOOP and the Stack that will be completed later on this year. So that’s basically where we see the volume ramp up coming from in our volumes is from those two plays. John Edwards And then lastly, just in terms of counterparty risk, to what extent are you baking that into your guidance? Derek Reiners Yes, John, I’ve covered that in our remarks. And there’s a new slide in the presentation that accompanies the news release that gives you a lot of detail on that. We actually feel very good about the counterparty credit risk that we have. And we’re not overly exposed to any particular customer, so good diversification. So we’re not expecting any sort of material credit losses. Operator And I’ll turn it back to Mr. T. D. Eureste for any additional or closing comments. End of Q&A T. D. Eureste Thank you. Our quiet period for the first quarter starts when we close our books in early April and extends till earnings are released after market closes in early May. Thank you for joining us. Operator And that will conclude today’s conference. We’d like to thank everyone for their participation. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) 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